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Schedule II Quarterly Report of Atlantic Power of Form 10-Q for the Quarter Ended June 30, 2011
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(a) of
the Securities Exchange Act of 1934 (Amendment No. 1)

Filed by the Registrant ý

Filed by a Party other than the Registrant o

Check the appropriate box:

ý

 

Preliminary Proxy Statement

o

 

Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2))

o

 

Definitive Proxy Statement

o

 

Definitive Additional Materials

o

 

Soliciting Material under §240.14a-12

 

ATLANTIC POWER CORPORATION

(Name of Registrant as Specified In Its Charter)

 

(Name of Person(s) Filing Proxy Statement, if other than the Registrant)

Payment of Filing Fee (Check the appropriate box):

o

 

No fee required.

o

 

Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.
    (1)   Title of each class of securities to which transaction applies:
        
 
    (2)   Aggregate number of securities to which transaction applies:
       

         
    (3)   Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined):
       

         
    (4)   Proposed maximum aggregate value of transaction:
        
 
    (5)   Total fee paid:
        
 

ý

 

Fee paid previously with preliminary materials.

o

 

Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.

 

 

(1)

 

Amount Previously Paid:
        
 
    (2)   Form, Schedule or Registration Statement No.:
        
 
    (3)   Filing Party:
        
 
    (4)   Date Filed:
        
 

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PRELIMINARY PROXY STATEMENT—SUBJECT TO COMPLETION—DATED SEPTEMBER 9, 2011

LOGO   LOGO

PROPOSED BUSINESS COMBINATION—YOUR VOTE IS VERY IMPORTANT

        On behalf of the boards of directors of Atlantic Power Corporation ("Atlantic Power") and of CPI Income Services Ltd., the general partner of Capital Power Income L.P. ("CPILP"), we send to you this management proxy circular and joint proxy statement that describes the proposed statutory plan of arrangement ("Plan of Arrangement") and related transactions whereby Atlantic Power will acquire, directly and indirectly, all of the outstanding limited partnership units of CPILP (the "Arrangement").

        CPILP unitholders will be permitted to exchange each of their limited partnership units for, at their election, C$19.40 in cash or 1.3 Atlantic Power common shares, subject to proration if total cash elections exceed approximately C$506.5 million or share elections exceed approximately 31.5 million Atlantic Power common shares. Based on the current number of Atlantic Power common shares outstanding (and specifically excluding any common shares of Atlantic Power that may be issued to finance the cash portion of the purchase price), the existing Atlantic Power shareholders will own approximately 70% of the combined company and former CPILP unitholders will own approximately 30%.

        Based on the closing price of the Atlantic Power common shares on the Toronto Stock Exchange ("TSX") of C$      on                                     , 2011, the transaction values CPILP at approximately C$           billion or C$          per unit. This represents a premium of approximately        % over CPILP's      -day volume-weighted average trading price on the TSX through June 17, 2011, the last trading day prior to the public announcement by Atlantic Power and CPILP of their proposed strategic combination.

        Capital Power Corporation ("Capital Power") and EPCOR Utilities Inc. ("EPCOR"), the direct and indirect holders of all of the issued and outstanding shares of CPI Investments Inc., which directly and indirectly holds an aggregate of approximately 29% of the outstanding limited partnership units of CPILP, have entered into agreements with Atlantic Power pursuant to which they each have agreed to support the Arrangement. In addition, in connection with completion of the Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power and the management agreements between Capital Power and CPILP will be terminated (or assigned to Atlantic Power).

        The transactions are subject to, among other things, certain approvals by the shareholders of Atlantic Power and the unitholders of CPILP. Specifically, at special meetings expected to be held on                        2011, Atlantic Power shareholders will be asked to approve an ordinary resolution that authorizes the issuance of the common shares of Atlantic Power necessary to complete the Arrangement and CPILP unitholders will be asked to approve a special resolution that authorizes the Arrangement, the Plan of Arrangement and certain other steps required to complete the Arrangement. The text of the resolutions are set forth in Annex F and G to this management proxy circular and joint proxy statement, respectively.

        The Atlantic Power board of directors unanimously recommends that the Atlantic Power shareholders vote "FOR" the ordinary resolution to issue the common shares necessary to complete the Arrangement.

        The board of directors of CPI Income Services Ltd., the general partner of CPILP, unanimously recommends that the CPILP unitholders vote "FOR" the special resolution to approve the Arrangement, the Plan of Arrangement and certain other steps required to complete the Arrangement.

        Your vote is very important, regardless of the number of shares or units you own. Whether or not you expect to attend the Atlantic Power or CPILP special meeting in person, please vote your shares or units as promptly as possible so that they may be represented and voted at the applicable special meeting.

        If you are unable to attend the Atlantic Power special meeting in person, please complete, date and sign the accompanying form of proxy (printed on                        paper) and return it, in the envelope provided to Computershare Trust Company of Canada, Proxy Department, 9th Floor, 100 University Avenue, Toronto, Ontario, M5J 2Y1, so that it is received not less than 48 hours, excluding Saturdays, Sundays and holidays, before the time fixed for holding the Atlantic Power special meeting or any adjournments or postponements thereof.


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        If you are unable to attend the CPILP special meeting in person, please complete, date and sign the accompanying form of proxy (printed on                    paper) and return it, in the envelope provided to Computershare Trust Company of Canada, Proxy Department, 9th Floor, 100 University Avenue, Toronto, Ontario, M5J 2Y1, so that it is received not less than 48 hours, excluding Saturdays, Sundays and holidays, before the time fixed for holding the CPILP special meeting or any adjournments or postponements thereof.

        We also encourage all registered CPILP unitholders to complete and return the enclosed letter of transmittal and election form (printed on                    paper) ("Letter of Transmittal and Election Form"), together with the certificate(s) representing your CPILP units, to Computershare Investor Services Inc. (the "Depositary") at the address specified in the Letter of Transmittal and Election Form. The Letter of Transmittal and Election Form contains procedural information relating to the Plan of Arrangement and should be reviewed carefully. To make a valid election as to the form of consideration that you wish to receive under the Plan of Arrangement (subject to proration), you must sign and return, if applicable, the Letter of Transmittal and Election Form and make a proper election thereunder and return it with accompanying CPILP unit certificate(s) to the Depositary prior to 5:00 p.m. (Mountain time) on                        , 2011, or, if the CPILP meeting is adjourned or postponed, such time on the third business day immediately prior to the date of such adjourned or postponed meeting (the "Election Deadline"). If you fail to make a proper election prior to the Election Deadline you will be deemed to have elected to receive Atlantic Power shares in respect of all of your CPILP units.

        If you are a non-registered holder of CPILP units or Atlantic Power shares and have received these materials through your broker, investment dealer or other intermediary, please follow the instructions provided by such broker, investment dealer or other intermediary to ensure that your vote is counted and, in the case of CPILP unitholders, for instructions and assistance in delivering your certificate(s) representing those units and, if applicable, making an election with respect to the form of consideration you wish to receive.

        More information about Atlantic Power, CPILP and the transaction, including other conditions, is contained in this management proxy circular and joint proxy statement. You should read this entire management proxy circular and joint proxy statement carefully, including the section entitled "Risk Factors" beginning on page 22. If you have any questions with regard to the procedures for voting or completing your transmittal documentation, please contact                            , our proxy solicitation agent, by telephone at                            toll-free or by e-mail at                                     .

        We look forward to the successful combination of Atlantic Power and CPILP and thank you for your ongoing support as we prepare to take this important step in creating a leading North American contracted power generation platform.

        Sincerely,

    

   

Barry E. Welch
President and Chief Executive Officer
Atlantic Power Corporation

  Stuart A. Lee
President
CPI Income Services Ltd.,
as General Partner of CPILP

        Neither the Securities and Exchange Commission nor any state securities commission nor any Canadian securities regulator has approved or disapproved of the securities to be issued under this management proxy circular and joint proxy statement or determined that this management proxy circular and joint proxy statement is accurate or complete. Any representation to the contrary is a criminal offense.

        This management proxy circular and joint proxy statement is dated                        , 2011 and is first being mailed to the shareholders of Atlantic Power and the unitholders of CPILP on or about                        , 2011.


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LOGO


NOTICE OF SPECIAL MEETING OF SHAREHOLDERS

        NOTICE IS HEREBY GIVEN that a special meeting of the holders of common shares of Atlantic Power Corporation will be held at the King Edward Hotel,                        , 37 King Street East, Toronto, Ontario on            , the            day of            , 2011 at the hour of         a.m. (Toronto time) for the following purposes:

        An "ordinary resolution" is a resolution passed by at least a majority of the votes cast by the Atlantic Power shareholders who voted in respect of that resolution at the Atlantic Power special meeting.

        Only Atlantic Power common shareholders of record at the close of business on            , 2011 are entitled to notice of and to attend the Atlantic Power special meeting or any adjournments or postponements thereof and to vote at the Atlantic Power special meeting. No person who becomes an Atlantic Power common shareholder after such date shall be entitled to receive notice of and vote at the Atlantic Power special meeting or any adjournment or postponement thereof.

        The accompanying management proxy circular and joint proxy statement provides additional information relating to the matters to be dealt with at the Atlantic Power special meeting and forms part of this notice.

        Your vote is important. Whether or not you expect to attend in person, we urge you to authorize a proxy to vote your shares as promptly as possible so that your shares may be represented and voted at the Atlantic Power special meeting.

        If you are unable to attend the Atlantic Power special meeting in person, please complete, date and sign the accompanying form of proxy and return it, in the envelope provided, to Computershare Trust Company of Canada, Proxy Department, 9th Floor, 100 University Avenue, Toronto, Ontario, M5J 2Y1, so that it is received by Computershare Trust Company of Canada not less than 48 hours, excluding Saturdays, Sundays and holidays, before the time fixed for holding the Atlantic Power special meeting or any adjournments or postponements thereof or by the chairman of the meeting prior to the commencement of the meeting or any adjournments or postponements thereof. The instrument appointing a proxy shall be in writing and shall be executed by the Atlantic Power common shareholder or the Atlantic Power common shareholder's attorney authorized in writing or, if the Atlantic Power common shareholder is a corporation, under its corporate seal by an officer or attorney thereof duly authorized.

        If you have any questions about the information contained in this document or require assistance in completing your proxy card, please contact Atlantic Power's proxy solicitor,                 , toll free at                 .


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IMPORTANT NOTICE REGARDING THE AVAILABILITY OF
PROXY MATERIALS FOR THE MEETING

        This management proxy circular and joint proxy statement is available at www.atlanticpower.com under "INVESTORS—Securities Filings."

        DATED at Toronto, Ontario this        day of            , 2011.

    BY ORDER OF THE BOARD OF DIRECTORS

 

 

/s/ IRVING GERSTEIN

Irving Gerstein
Chair of the Board of Directors
Atlantic Power Corporation

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LOGO


NOTICE OF SPECIAL MEETING OF UNITHOLDERS

        NOTICE IS HEREBY GIVEN that, pursuant to an interim order of the Court of Queen's Bench of Alberta dated                        , 2011 ("Interim Order"), a special meeting of the holders of limited partnership units of Capital Power Income L.P. will be held at        at         a.m. (Edmonton time) on                        , 2011 for the following purposes:

        As an "extraordinary resolution," the Arrangement Resolution must be passed by not less than 662/3% of the votes cast by the CPILP unitholders, in person or by proxy, at the CPILP special meeting. The Arrangement Resolution must also be passed by not less than a simple majority of the vote cast by the CPILP unitholders, in person or by proxy, at the CPILP special meeting after excluding those votes required to be excluded by the minority approval provisions of Multilateral Instrument 61-101—Protection of Minority Security Holders in Special Transactions.

        Only CPILP unitholders of record at the close of business on                        , 2011 are entitled to notice of and to attend the CPILP special meeting or any adjournments or postponements thereof and to vote at the CPILP special meeting. No person who becomes a CPILP unitholder after such date shall be entitled to receive notice of and vote at the CPILP special meeting or any adjournment or postponement thereof.

        The accompanying management proxy circular and joint proxy statement accompanying this notice provides additional information relating to the matters to be dealt with at the CPILP special meeting and is incorporated into and forms part of this notice.

        Your vote is important. Whether or not you expect to attend in person, we urge you to authorize a proxy to vote your CPILP units as promptly as possible so that your CPILP units may be represented and voted at the CPILP special meeting.

        If you are unable to attend the CPILP special meeting in person, please complete, date and sign the accompanying form of proxy and return it, in the envelope provided to Computershare Trust Company of Canada, Proxy Department, 9th Floor, 100 University Avenue, Toronto, Ontario, M5J 2Y1, so that it is received by Computershare Trust Company of Canada not less than 48 hours, excluding Saturdays, Sundays and holidays, before the time fixed for holding the CPILP special meeting or any adjournments or postponements thereof. The instrument appointing a proxy shall be in writing and shall be executed by the CPILP unitholder or the CPILP unitholder's attorney authorized in writing or, if the CPILP unitholder is a corporation, under its corporate seal by an officer or attorney thereof duly authorized.

        If you have any questions about the information contained in this document or require assistance in completing your proxy card, please contact CPILP's proxy solicitor, Georgeson Shareholder Communications Canada, Inc., toll free at            .


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        DATED at Edmonton, Alberta this        day of                        , 2011.

    BY ORDER OF THE BOARD OF DIRECTORS OF CPI INCOME SERVICES LTD., AS GENERAL PARTNER OF CAPITAL POWER INCOME L.P.

 

 

/s/ BRIAN T. VAASJO

Brian T. Vaasjo
Chairman
CPI Income Services Ltd.
as General Partner of CPILP

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ADDITIONAL INFORMATION

        This management proxy circular and joint proxy statement incorporates important business and financial information about Atlantic Power from other documents that are not included in or delivered with this management proxy circular and joint proxy statement. This information is available to you without charge upon your request. You can obtain the documents incorporated by reference into this management proxy circular and joint proxy statement by requesting them in writing or by telephone from the appropriate entity at the following addresses and telephone numbers:

Atlantic Power Corporation
200 Clarendon Street, Floor 25
Boston, Massachusetts 02116
Attn: Investor Relations
617-977-2700

        Investors may also consult Atlantic Power's and CPILP's website for more information about Atlantic Power and CPILP, respectively. Atlantic Power's website is www.atlanticpower.com. CPILP's website is www.capitalpowerincome.ca. Information included on these websites is not incorporated by reference into this management proxy circular and joint proxy statement.

        If you would like to request any documents, please do so by            , 2011 in order to receive them before the special meetings.

        For a more detailed description of the information incorporated by reference in this management circular and joint proxy statement and how you may obtain it, see "Where You Can Find More Information" beginning on page 150.


ABOUT THIS JOINT PROXY STATEMENT

        For ease of reference, we refer to this management proxy circular and joint proxy as this "joint proxy statement".

        This joint proxy statement constitutes a proxy statement of Atlantic Power under Section 14(a) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and a management proxy circular of both Atlantic Power and CPILP under National Instrument 51-102 Continuous Disclosure Obligations ("NI 51-102") of the Canadian Securities Administrators (the "CSA"). It also constitutes a notice of meeting with respect to the special meeting of Atlantic Power shareholders and a notice of meeting with respect to the special meeting of CPILP unitholders.

        You should rely only on the information contained in or incorporated by reference into this joint proxy statement. No one has been authorized to provide you with information that is different from that contained in, or incorporated by reference into, this joint proxy statement. This joint proxy statement is dated              . You should not assume that the information contained in this joint proxy statement is accurate as of any date other than that date. Neither the mailing of this joint proxy statement to Atlantic Power shareholders or CPILP unitholders nor the issuance by Atlantic Power of common shares in connection with the Arrangement will create any implication to the contrary.

        This joint proxy statement does not constitute an offer to sell, or a solicitation of an offer to buy, any securities, or the solicitation of a proxy, in any jurisdiction to or from any person to whom it is unlawful to make any such offer or solicitation. Information contained in this joint proxy statement regarding Atlantic Power has been provided by Atlantic Power and information contained in this joint proxy statement regarding CPILP has been provided by CPILP.

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TABLE OF CONTENTS

QUESTIONS AND ANSWERS

  v

SUMMARY

  1
 

The Entities

  1
 

The Arrangement Agreement and Plan of Arrangement

  2
 

Summaries of Other Agreements Relating to the Arrangement

  7
 

The Atlantic Power Special Meeting

  9
 

The CPILP Special Meeting

  10
 

Appraisal/Dissent Rights

  12
 

U.S. Securities Law Matters

  12
 

Material Canadian Federal Income Tax Consequences

  12
 

Material U.S. Federal Income Tax Consequences

  12
 

Atlantic Power Financing

  13
 

Selected Historical Consolidated Financial Data of Atlantic Power

  14
 

Selected Historical Consolidated Financial Data of CPILP

  15
 

Summary Unaudited Pro Forma Condensed Combined Consolidated Financial Information

  16
 

Selected Comparative Per Share/Unit Market Price and Dividend Information

  18
 

Certain Historical and Pro Forma Per Share/Unit Data

  19
 

Exchange Rate Information

  21

RISK FACTORS

  22
 

Risk Factors Relating to the Plan of Arrangement

  22
 

Risk Factors Relating to the Combined Company Following the Plan of Arrangement

  24

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

  30

THE ENTITIES

  32
 

Atlantic Power Corporation

  32
 

Capital Power Income L.P.

  32
 

CPI Income Services Ltd.

  33
 

CPI Investments Inc.

  33

THE ATLANTIC POWER SPECIAL MEETING

  34
 

Date, Time and Place

  34
 

Purpose of the Special Meeting

  34
 

Recommendations of the Board of Directors of Atlantic Power

  34
 

Share Issuance Resolution

  34
 

Record Date; Shares Entitled to Vote

  35
 

Share Ownership by and Voting Rights of Directors and Executive Officers

  35
 

Quorum

  35
 

Required Vote

  35
 

Failure to Vote and Broker Non-Votes

  35
 

Appointment of Proxyholder

  35
 

Record Holders

  36
 

Shares Held in Street Name/Non-Registered Shareholders

  36
 

Revocability of Proxy; Changing Your Vote

  37
 

Additional Disclosure Required by Canadian Securities Laws

  37

THE CPILP SPECIAL MEETING

  39
 

Date, Time and Place

  39
 

Purpose of the Special Meeting

  39
 

Recommendations of the Board of Directors of the General Partner

  39
 

Record Date; Units Entitled to Vote

  39
 

Unit Ownership by and Voting Rights of Directors and Executive Officers

  39
 

Quorum

  40
 

Required Vote

  40
 

Failure to Vote and Broker Non-Votes

  40

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Table of Contents

 

Appointment of Proxyholder

  40
 

Record Holders

  40
 

Units Held in Street Name/Non-Registered CPILP Unitholders

  41
 

Revocability of Proxy; Changing Your Vote

  41
 

Solicitation of Proxies

  42
 

Principal Unitholders

  42
 

Procedures for the Surrender of Unit Certificate and Receipt of Consideration

  42

APPRAISAL/DISSENT RIGHTS

  47

THE ARRANGEMENT AGREEMENT AND PLAN OF ARRANGEMENT

  48
 

Effects of the Plan of Arrangement

  48
 

Background of the Plan of Arrangement

  48
 

Atlantic Power's Reasons for the Arrangement Agreement; Recommendations of Atlantic Power's Board of Directors

  55
 

Opinions of Atlantic Power's Financial Advisors

  58
 

Interests of Atlantic Power Directors and Officers in the Plan of Arrangement

  75
 

Certain Atlantic Power Prospective Financial Information

  75
 

CPILP's Reasons for the Plan of Arrangement; Recommendations of the Board of Directors of CPILP's General Partner

  77
 

Opinions of CPILP's Financial Advisors

  81
 

Interests of CPILP Directors and Officers in the Plan of Arrangement

  82
 

Certain CPILP Prospective Financial Information

  83
 

Accounting Treatment of the Arrangement

  84
 

Court Approval Required for the Plan of Arrangement

  85
 

Canadian Securities Law Matters

  85
 

United States Securities Law Matters

  87
 

Stock Exchange Approvals

  88
 

Regulatory Approvals Required for the Plan of Arrangement and Other Regulatory Matters

  88
 

Listing of Atlantic Power Shares

  91
 

Appraisal/Dissent Rights

  91
 

Litigation Related to the Plan of Arrangement

  91
 

Effect of the Plan of Arrangement on CPILP's Other Securities

  92

SUMMARY OF THE ARRANGEMENT AGREEMENT

  93
 

Representations and Warranties

  93
 

Conditions Precedent to the Plan of Arrangement

  94
 

Covenants

  99
 

Termination of the Arrangement Agreement

  102
 

Governing Law

  104
 

Summaries of Other Agreements Relating to the Arrangement

  104

MATERIAL CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

  108
 

Disposition of CPILP Units Pursuant to the Plan of Arrangement

  108
 

Holding and Disposing of Atlantic Power common shares

  110
 

Taxation of Capital Gains and Capital Losses

  111
 

Alternative Minimum Tax

  111
 

Eligibility for Investment

  111

CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

  112

ATLANTIC POWER FINANCING

  113

INFORMATION REGARDING ATLANTIC POWER

  114
 

General

  114
 

Trading Price and Volume

  114
 

Prior Sales

  116
 

Description of Common Shares

  118
 

Security Ownership of Certain Beneficial Owners and Management

  119
 

Risk Factors

  120

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INFORMATION REGARDING CPILP

  121
 

Presentation of Information

  121
 

General

  121
 

Recent Developments

  121
 

Additional Information Relating to CPILP

  122
 

Price Range and Trading Volume of CPILP Units

  123
 

Dividend History

  123
 

Voting Securities and Principal Holders of Voting Securities

  124
 

Ownership of CPILP Securities by Directors, Officers and Insiders

  124
 

Indebtedness of Directors and Executive Officers

  125
 

Risk Factors

  125
 

Auditors, Transfer Agent and Registrar

  126
 

Selected Historical Consolidated Financial Data of CPILP

  126

INFORMATION REGARDING THE COMBINED COMPANY

  128
 

General

  128
 

Directors and Executive Officers of the Combined Company

  128

ATLANTIC POWER AND CPILP UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

  129

COMPARATIVE PER SHARE/UNIT MARKET PRICE DATA AND DIVIDEND INFORMATION

  139

CERTAIN HISTORICAL AND PRO FORMA PER SHARE/UNIT DATA

  140

COMPARISON OF RIGHTS OF ATLANTIC POWER SHAREHOLDERS AND CPILP UNITHOLDERS

  142

SHAREHOLDER PROPOSALS

  149

HOUSEHOLDING

  149

WHERE YOU CAN FIND MORE INFORMATION

  150

CANADIAN SECURITIES LAW MATTERS

  151
 

Legal Matters

  151
 

Experts

  151
 

Information Filed on SEDAR

  151

ANNEX A

 

ARRANGEMENT AGREEMENT

   

ANNEX B

 

OPINION OF TD SECURITIES INC.

   

ANNEX C

 

OPINION OF MORGAN STANLEY & CO. LLC

   

ANNEX D

 

OPINION OF CIBC WORLD MARKETS INC.

   

ANNEX E

 

OPINION OF GREENHILL & CO. CANADA LTD.

   

ANNEX F

 

ATLANTIC POWER'S SHARE ISSUANCE RESOLUTION

   

ANNEX G

 

CPILP'S ARRANGEMENT RESOLUTION

   

ANNEX H

 

INTERIM ORDER

   

ANNEX I

 

NOTICE OF APPLICATION FOR FINAL ORDER

   

ANNEX J

 

FORM OF PROXY OF ATLANTIC POWER

   

ANNEX K

 

FORM OF PROXY OF CPILP

   

SUPPLEMENTAL INFORMATION DELIVERED TO ATLANTIC POWER SHAREHOLDERS

SCHEDULE I

 

ANNUAL REPORT OF ATLANTIC POWER ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2010

   

SCHEDULE II

 

QUARTERLY REPORT OF ATLANTIC POWER ON FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2011

   

SCHEDULE III

 

CPILP ANNUAL INFORMATION FORM DATED MARCH 11, 2011

   

SCHEDULE IV

 

AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF CPILP (DECEMBER 31, 2010, 2009 AND 2008)

   

SCHEDULE V

 

CPILP MANAGEMENT'S DISCUSSION AND ANALYSIS (DECEMBER 31, 2010)

   

SCHEDULE VI

 

UNAUDITED CONDENSED INTERIM FINANCIAL STATEMENTS OF CPILP (JUNE 30, 2011)

   

SCHEDULE VII

 

CPILP MANAGEMENT'S DISCUSSION AND ANALYSIS (JUNE 30, 2011)

   

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QUESTIONS AND ANSWERS

        Set forth below are questions that you, as a shareholder of Atlantic Power or unitholder of CPILP, may have regarding the Plan of Arrangement and the other matters to be considered at the special meetings of shareholders of Atlantic Power and unitholders of CPILP and the answers to those questions. Atlantic Power and CPILP urge you to read carefully the remainder of this joint proxy statement because the information in this section does not provide all the information that might be important to you with respect to the Plan of Arrangement and the other matters to be considered at the special meetings. Atlantic Power, following completion of the Plan of Arrangement, is sometimes referred to in this joint proxy statement as the "Combined Company". All references to US$ or $ are to United States dollars, and all references to C$ are to Canadian dollars.

Q:    Why am I receiving this joint proxy statement?

A:
Atlantic Power and CPILP have entered into the Arrangement Agreement pursuant to which Atlantic Power has agreed to acquire, directly and indirectly, all of the outstanding CPILP units pursuant to a Plan of Arrangement under the Canada Business Corporations Act (the "CBCA"), all as more fully described in this joint proxy statement. In order to effect the Plan of Arrangement:

Atlantic Power shareholders must approve the Share Issuance Resolution attached hereto as Annex F approving the issuance of Atlantic Power common shares to be issued in consideration for the acquisition of CPILP units as is necessary to complete the Arrangement; and

CPILP unitholders must approve the Arrangement Resolution attached hereto as Annex G approving the Arrangement, the Plan of Arrangement and certain other steps required to complete the Arrangement.

Atlantic Power and CPILP will hold separate special meetings to obtain these approvals. This joint proxy statement contains important information about the Plan of Arrangement and the special meetings of shareholders of Atlantic Power and unitholders of CPILP.

Your vote is important. You do not need to attend the special meetings in person to vote. Atlantic Power and CPILP encourage you to vote as soon as possible.

Q:    Is the Arrangement supported by the boards of directors of Atlantic Power and CPI Income Services Ltd. as the general partner of CPILP?

A:
Yes. The board of directors of Atlantic Power has unanimously determined that (i) the Arrangement is in the best interests of Atlantic Power and is fair to Atlantic Power's stakeholders, (ii) Atlantic Power should enter into the Arrangement Agreement, and (iii) Atlantic Power's shareholders should vote FOR the Share Issuance Resolution.

In making its recommendation, the Atlantic Power board of directors considered a number of factors as described in this joint proxy statement under the heading "The Arrangement Agreement and Plan of Arrangement—Atlantic Power's Reasons for the Arrangement Agreement; Recommendations of Atlantic Power's Board of Directors."

The members of the board of directors of CPI Income Services Ltd., the general partner of CPILP, entitled to vote, being the independent directors of CPI Income Services Ltd., the general partner of CPILP, determined unanimously that the Arrangement is in the best interests of CPILP and is fair to the CPILP unitholders and resolved unanimously to recommend to the CPILP unitholders that they vote FOR the Arrangement Resolution. The members of the board of directors of CPI Income Services Ltd., the general partner of CPILP, entitled to vote also unanimously approved the Arrangement and the execution and performance of the Arrangement Agreement.

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Q:    What are Atlantic Power's and CPILP's reasons for the entering into the Arrangement Agreement?

A:
The boards of directors of Atlantic Power and of CPI Income Services Ltd., the general partner of CPILP, each concluded that the potential benefits they expect from combining Atlantic Power and CPILP, including, among other things, strengthening Atlantic Power's dividend sustainability for the foreseeable future as a result of immediate accretion to cash available for distribution, creation of a combined company with a larger and more diversified portfolio and anticipated enhanced access to capital, outweighed the uncertainties, risks and potentially negative factors relevant to the Plan of Arrangement. For a more detailed discussion of the reasoning of Atlantic Power's board of directors and the board of directors of CPI Income Services Ltd., the general partner of CPILP, see "The Arrangement Agreement and Plan of Arrangement—Atlantic Power's Reasons for the Arrangement Agreement; Recommendations of Atlantic Power's Board of Directors" and "—CPILP's Reasons for the Plan of Arrangement; Recommendations of the Board of Directors of CPILP's General Partner" in this joint proxy statement, beginning on pages 55 and 77, respectively.

Q:    What is a plan of arrangement?

A:
A plan of arrangement is a statutory procedure under Canadian corporate law that allows companies to carry out transactions with securityholders and court approval. The Plan of Arrangement you are being asked to consider will allow Atlantic Power to acquire, directly and indirectly, all of the outstanding CPILP units.

Q:    If I am a CPILP unitholder, how do I elect to receive my consideration under the Plan of Arrangement?

A:
Each registered holder of CPILP units prior to the deadline for making consideration elections, being 5:00 p.m. (Edmonton time) on                    , 2011, will have the right to elect in the Letter of Transmittal and Election Form to be sent by CPILP to the CPILP unitholders in connection with the Plan of Arrangement to receive the consideration set out above, subject to proration.

CDS Clearing and Depositary Services Inc. is the only registered holder of CPILP units. All other holders of CPILP units should contact the broker, investment dealer or other intermediary through which they hold CPILP units for instructions and assistance in making an election with respect to the form of consideration they wish to receive.

If you fail to make a proper election by the election deadline, you will be deemed to have elected to receive share consideration for all of your CPILP units, subject to proration.

Q:    If I am a CPILP unitholder, am I assured of receiving the exact form of consideration I elect to receive?

A:
No. Both the aggregate number of Atlantic Power common shares and the aggregate amount of cash to be paid to CPILP unitholders under the Plan of Arrangement are fixed. All cash elections will be subject to proration if total cash elections exceed approximately C$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares. Accordingly, there is no assurance that you will receive the form of consideration you elect with respect to all of your CPILP units. If the elections of all CPILP unitholders result in an oversubscription for Atlantic Power common shares or cash,

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Q:    What is the value of the consideration to be received under the Plan of Arrangement?

A:
If the Plan of Arrangement is completed, holders of CPILP units will receive, at their election, C$19.40 per unit in cash or 1.3 Atlantic Power common shares per unit, subject to proration if total cash elections exceed approximately C$506.5 million or share elections exceed approximately 31.5 million Atlantic Power common shares. Because Atlantic Power will issue a fixed number of Atlantic Power common shares in exchange for each CPILP unit, the market value of the consideration that CPILP unitholders will receive will depend on the price per Atlantic Power common share at the time the transaction is completed. That price will not be known at the time of the special meetings and may be less or more than the current price or the price at the time of the special meetings.

Q:    How does Atlantic Power intend to finance the cash portion of the consideration to be received under the Plan of Arrangement?

A:
Atlantic Power intends to finance the cash portion of the purchase price to complete the Plan of Arrangement by issuing up to approximately C$200.0 million of equity and up to approximately C$425.0 million of debt through public and private offerings. However, in the event that such financing is not available on terms satisfactory to Atlantic Power, Atlantic Power has received an executed commitment letter (the "TLB Commitment Letter"), evidencing the commitment of a Canadian chartered bank and another financial institution to structure, arrange, underwrite and syndicate a senior secured credit facility consisting of a term B loan facility (the "Tranche B Facility") in the amount of $625 million, subject to the terms and conditions set forth therein.

Q:    Will the Atlantic Power common shares be traded on an exchange?

A:
It is a condition of the completion of the Plan of Arrangement that the common shares of Atlantic Power received under the Plan of Arrangement be approved for listing on the NYSE and on the TSX.

Q:    Why are the North Carolina facilities being sold to Capital Power rather than being included in the transaction?

A:
The North Carolina facilities are not of strategic interest to Atlantic Power. At the time of, and leading up to, the signing of the Arrangement Agreement, there was uncertainty surrounding the negotiations and finalized terms of the power purchase agreements for these facilities. Capital Power agreed to purchase the North Carolina facilities to facilitate the consummation of the transaction. The price of approximately C$121.4 million was negotiated in good faith between the independent directors of CPI Income Services Ltd., as general partner of CPILP, and Capital Power. CIBC World Markets Inc. ("CIBC") provided a written opinion to the special committee of the board of directors of CPI Income Services Ltd., as general partner of CPILP, and to the independent director of CPI Preferred Equity Ltd. that the consideration to be received by CPI Preferred Equity Ltd. pursuant to the membership interest purchase agreement in respect of the North Carolina assets is fair, from a financial point of view, to CPI Preferred Equity Ltd.

Q:    How is the Plan of Arrangement expected to impact the payment of dividends on Atlantic Power common shares?

A:
The transactions contemplated by the Plan of Arrangement are expected to be immediately accretive to cash available for distribution following the effective date of the Plan of Arrangement

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Q:    If I hold CPILP units will I still be paid distributions prior to the Effective Date?

A:
CPILP expects to continue to pay monthly distributions to CPILP unitholders up to and including the month immediately preceding the month in which the Effective Date occurs. However, no distribution shall be paid unless and until the board of directors of CPI Income Services Ltd., the general partner of CPILP, in its sole discretion, makes a declaration that such distribution is payable.

Q:    When and where will the special meetings be held?

A:
The Atlantic Power special meeting will be held at the King Edward Hotel,                                     , 37 King Street East, Toronto, Ontario                        on                         , 2011 at           a.m., Toronto time.

The CPILP special meeting will be held at                              on                     , 2011 at                     a.m., Edmonton time.

Q:    Who is entitled to vote at the Atlantic Power and CPILP special meetings?

A:
Atlantic Power has fixed                    , 2011 as the record date for the Atlantic Power special meeting. If you were an Atlantic Power shareholder as of the close of business on such date, you are entitled to vote on matters that come before the Atlantic Power special meeting.

CPILP has fixed                    , 2011 as the record date for the CPILP special meeting. If you were a CPILP unitholder as of the close of business on such date, you are entitled to vote on matters that come before the CPILP special meeting.

Q:    What vote is required to approve each of the Share Issuance Resolution and the Arrangement Resolution?

A:
Atlantic Power:    The Share Issuance Resolution must be approved by a majority of the votes cast by Atlantic Power shareholders, either in person or by proxy, at the Atlantic Power special meeting.

CPILP:    Pursuant to the Interim Order, the Arrangement Resolution must be approved by not less than 662/3% of the votes cast by CPILP unitholders, either in person or by proxy, at the CPILP special meeting. In addition, the Arrangement Resolution must be approved by a simple majority of the votes cast by CPILP unitholders present in person or by proxy at the CPILP special meeting, after excluding those votes required to be excluded by the minority approval provisions of MI 61-101, such as the votes cast by CPI Income Services Ltd., as general partner of CPILP, and CPI Investments, Inc. ("CPI Investments"). Notwithstanding the foregoing, the Arrangement Resolution authorizes the board of directors of CPI Income Services Ltd., the general partner of CPILP, without further notice to or approval of the unitholders, subject to the terms of the Plan of Arrangement and the Arrangement Agreement, to amend the Plan of Arrangement or the Arrangement Agreement or to decide not to proceed with the Plan of Arrangement at any time prior to the Plan of Arrangement becoming effective pursuant to the provisions of the CBCA. Capital Power and EPCOR, the direct and indirect holders of all of the issued and outstanding

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Q:    How many votes do I have?

A:
Atlantic Power:    You are entitled to one vote for each Atlantic Power common share that you owned as of the close of business on the Atlantic Power record date. As of the close of business on the Atlantic Power record date, there were approximately                                    outstanding Atlantic Power common shares.

CPILP:    You are entitled to one vote for each CPILP unit that you owned as of the close of business on the CPILP record date. As of the close of business on the CPILP record date, there were 56,597,899 outstanding CPILP units.

Q:    How do I vote?

A:
If you are a registered shareholder of Atlantic Power as of the close of business on the record date for the Atlantic Power special meeting or a registered unitholder of CPILP as of the close of business on the record date for the CPILP special meeting, you may vote in person by attending your respective special meeting or, to ensure your shares or units are represented at the meeting, you may authorize a proxy to vote by:

accessing the Internet website specified on your form of proxy;

calling the toll-free number specified on your form of proxy; or

signing and returning your form of proxy in the postage-paid envelope provided.

If you hold Atlantic Power common shares or CPILP units in "street name" through a stock brokerage account or through a bank or other nominee, please follow the voting instructions provided by your broker, investment dealer or other intermediary to ensure that your shares or units are represented at the applicable special meeting. CDS Clearing and Depositary Services Inc. is the only registered holder of CPILP units. All other holders of CPILP units beneficially hold those units in "street name" and should follow the voting instructions provided by their broker, investment dealer or other intermediary.

Q:    My shares or units are held in "street name" by my broker or I am a non-registered shareholder or unitholder. Will my broker automatically vote my shares or units for me?

A:
No. If your shares or units are held in the name of a broker, investment dealer or other intermediary, you are considered the "beneficial owner" of the shares or units held for you in what is known as "street name." You are not the "record holder" or "registered holder" of such shares or units. If this is the case, this joint proxy statement has been forwarded to you by your broker, investment dealer or other intermediary. As the beneficial owner, unless your broker, investment dealer or other intermediary has discretionary authority over your shares or units, you generally have the right to direct your broker, investment dealer or other intermediary as to how to vote your shares or units. If you do not provide voting instructions, your shares or units will not be voted on any resolutions on which your broker, investment dealer or other intermediary does not have discretionary authority.

Please follow the voting instructions provided by your broker, investment dealer or other intermediary so that it may vote your shares or units on your behalf. Please note that you may not vote shares or units held in street name by returning a form of proxy directly to Atlantic Power or

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Q:    What will happen if I return my form of proxy without indicating how to vote?

A:
If you are a registered holder of Atlantic Power common shares or a registered holder of CPILP units and you sign and return your form of proxy without indicating how to vote on the Share Issuance Resolution or Arrangement Resolution, as applicable, the Atlantic Power common shares or CPILP units represented by your proxy will be voted "FOR" the Share Issuance Resolution and "FOR" the Arrangement Resolution, as applicable.

Q:    What constitutes a quorum?

A:
Atlantic Power:    A quorum must be present at the special meeting for any business to be conducted. Pursuant to Atlantic Power's articles, the presence of two persons, present in person, each being a shareholder entitled to vote or a duly appointed proxy for a shareholder so entitled, constitutes a quorum. For purposes of counting votes, abstentions and broker non-votes will not be counted as votes cast at the Atlantic Power special meeting.

CPILP:    A quorum must be present at the CPILP special meeting for any business to be conducted. Pursuant to the limited partnership agreement of CPILP, the quorum for the CPILP special meeting is one or more CPILP unitholders present in person or by proxy representing at least 10% of the outstanding units.

Q:    Can I change my vote after I have returned a proxy or voting instruction card?

A:
Yes.

If you are a registered holder of Atlantic Power common shares as of the close of business on the record date for the Atlantic Power special meeting:    You can change your vote at any time before the start of the Atlantic Power special meeting, unless otherwise noted. In addition to revocation in any other manner permitted by law, you can revoke your proxy in one of the following ways:

you can grant a new, valid proxy bearing a later date (including by telephone or Internet);

you can deposit a signed notice of revocation at Atlantic Power's registered office at any time up to and including the last business day preceding the day of the Atlantic Power special meeting (or any adjournment or postponement thereof) or with the chair of the Atlantic Power special meeting on the day of the Atlantic Power special meeting (or any adjournment or postponement thereof); or

you can attend the special meeting and vote in person, which will automatically cancel any proxy previously given, or you may revoke your proxy in person, but your attendance alone will not revoke any proxy that you have previously given.

If you choose any of the foregoing methods, your notice of revocation or your new proxy must be received by Atlantic Power no later than the beginning of the Atlantic Power special meeting. If you have voted your shares by telephone or through the Internet, you may revoke your prior telephone or Internet vote by any manner described above. Only your latest dated proxy will count.

If you are a registered holder of CPILP units as of the close of business on the record date for the CPILP special meeting:    You can change your vote at any time before the start of the CPILP

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Q:    What other approvals are required for the Plan of Arrangement?

        

A:
The Arrangement is subject to certain regulatory approvals, including approval under the Investment Canada Act, the Competition Act (Canada), the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (United States) and from the Federal Energy Regulatory Commission under the United States Federal Power Act, as more particularly set forth in the Arrangement Agreement. A "no action" letter and waiver from the merger notification provision under the Competition Act was received on August 26, 2011 and early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act was granted on August 26, 2011.

The Arrangement must also be approved by the Court of Queen's Bench of Alberta. The court will be asked to make an order approving the Arrangement and determine that the Arrangement is fair to the CPILP unitholders. CPILP, CPI Income Services Ltd., as general partner of CPILP, and CPI Investments will apply to the court for this order if the regulatory approvals described above have been obtained and the CPILP unitholders approve the Arrangement Resolution at the CPILP special meeting.

In addition, in connection with the Arrangement, certain regulatory approvals of the power generation regulatory authorities that have jurisdiction over CPILP's projects are required.

Q:    What are the material Canadian federal income tax consequences of the Plan of Arrangement to holders of CPILP units?

A:
CPILP unitholders will realize a taxable disposition of their CPILP units under the Plan of Arrangement. Eligible holders that receive Atlantic Power common shares pursuant to the Plan of Arrangement will be entitled to make a joint tax election with Atlantic Power under the Income Tax Act (Canada) (the "Tax Act") that will, depending on the circumstances of each particular unitholder, allow for a full or partial deferral of taxable gains that would otherwise be realized.

Atlantic Power common shares will be considered "qualified investments" for registered retirement savings plans and other tax-exempt plans.

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Q:    When do you expect the Plan of Arrangement to be completed?

A:
Atlantic Power and CPILP are working to complete the Plan of Arrangement in the fourth quarter of 2011. However, the Plan of Arrangement is subject to obtaining various regulatory approvals and other conditions, and it is possible that factors outside the control of both entities could result in the Plan of Arrangement being completed at a later date, or not at all. There may be a substantial amount of time between the respective Atlantic Power and CPILP special meetings and the completion of the Plan of Arrangement. Atlantic Power and CPILP hope to complete the Plan of Arrangement as soon as reasonably practicable.

Q:    What will happen to CPILP if the Plan of Arrangement is completed?

A:
If the Plan of Arrangement is completed, Atlantic Power will acquire all of the CPILP units and CPILP will become a wholly-owned subsidiary of Atlantic Power. Atlantic Power intends to have the CPILP units de-listed from the TSX.

Q:    What do I need to do now?

        

A:
You should carefully read and consider the information contained in, and/or incorporated by reference into, this joint proxy statement. Registered holders of Atlantic Power shares or CPILP units should then vote by completing the enclosed form of proxy or, alternatively, by telephone, or over the Internet, in each case in accordance with the enclosed instructions.

If you hold your Atlantic Power common shares or CPILP units through a broker, investment dealer or other intermediary, please follow the instructions provided by such broker, investment dealer or other intermediary to ensure that your vote is counted at the meeting and, if you are a CPILP unitholder, making an election with respect to the form of consideration you wish to receive in exchange for your CPILP units.

Q:    As a registered holder of CPILP units, should I send in my Letter of Transmittal and Election Form and CPILP unit certificates now?

A:
Yes. It is recommended that all registered holders of CPILP units complete, sign and return the Letter of Transmittal and Election Form with accompanying CPILP unit certificate(s) to Computershare Investor Services Inc. as soon as possible. To make a valid election as to the form of consideration that you wish to receive under the Plan of Arrangement (subject to proration), you must complete, sign and return the Letter of Transmittal and Election Form and make a proper election thereunder and return it with accompanying CPILP unit certificate(s) to Computershare Investor Services Inc. prior to the election deadline, being 5:00 p.m. (Edmonton time) on                    , 2011. If you fail to make a proper election by the election deadline, you will be deemed to have elected to receive share consideration for all of your CPILP units, subject to proration.

Q:    If my CPILP units are held in street name by my broker, investment dealer or other intermediary, will my broker automatically make an election for me?

A:
No, a broker, investment dealer or other intermediary will make an election on your behalf, only if you provide instructions to them on which election to make or if they have discretionary authority over your units. Without instructions, no election will be made on your behalf (unless they have

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Q:    Are shareholders or unitholders entitled to appraisal/dissent rights?

A:
Atlantic Power:    The shareholders of Atlantic Power are not entitled to dissent rights in connection with the Share Issuance Resolution.

CPILP:    The unitholders of CPILP are not entitled to dissent rights in connection with the Arrangement Resolution.

Q:    What happens if I sell my shares or units before the special meeting?

A:
The record date of each of the special meetings is          , 2011. If you transfer your shares or units after the applicable record date but before the applicable special meeting, you will retain your right to vote at the applicable special meeting.

Q.    If the Plan of Arrangement is approved, can I sell my CPILP units after the special meeting but before completion of the Plan of Arrangement?

A.
The Letter of Transmittal and Election Form to be completed by registered holders of CPILP units provides that the deposit of CPILP units is irrevocable. Accordingly, a registered holder of CPILP units that has validly deposited units and made an election will not be able to withdraw and sell those units after so doing. Notwithstanding the irrevocable nature of the deposit of units, elections as to the form of consideration may be changed prior to the election deadline, being 5:00 p.m. (Edmonton time) on                    , 2011, by submitting a new Letter of Transmittal and Election Form.

If you hold your CPILP units in "street name," once you have provided your broker, investment dealer or other intermediary with your election as to the form of consideration to be received, your broker, investment dealer or other intermediary will make an election on your behalf via an online system set up by CDS Clearing and Depository Services Inc. Once your election has been submitted, this effectively "freezes" your CPILP units such that you will not be able to sell your units after making an election unless your broker, investment dealer or other intermediary makes an online withdrawal. An online withdrawal could only be made prior to the election deadline, being            , 2011.

Q:    Who is soliciting my proxy?

A:
Atlantic Power:    Your proxy is being solicited by or on behalf of management of Atlantic Power for use at the Atlantic Power special meeting and any adjournment or postponement thereof. All associated costs of the proxy solicitation will be borne by Atlantic Power. In addition to the use of the mail, proxies may be solicited by directors, officers and other employees of Atlantic Power, without additional remuneration, by personal interview, telephone, facsimile or otherwise. Atlantic Power will also request brokerage firms, nominees, custodians and fiduciaries to forward proxy materials to the beneficial owners of shares and will provide customary reimbursement to such firms for the cost of forwarding these materials. Atlantic Power has retained            to assist in its solicitation of proxies and has agreed to pay them a fee of approximately                              , plus reasonable expenses, for these services.

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Q:    What if I hold both Atlantic Power common shares and CPILP units?

A:
If you are a shareholder of Atlantic Power and a unitholder of CPILP, you will receive two separate packages of proxy materials. A vote as a CPILP unitholder will not count as a vote as an Atlantic Power shareholder, and a vote as an Atlantic Power shareholder will not count as a vote as a CPILP unitholder. Therefore, please separately vote each of your CPILP units and Atlantic Power common shares.

Q:    Who can help answer my questions?

A:
CPILP unitholders or Atlantic Power shareholders who have questions about the Plan of Arrangement or the other matters to be voted on at the special meetings or desire additional copies of this joint proxy statement or additional forms of proxy should contact:

If you are an Atlantic Power shareholder:   If you are a CPILP unitholder:

Atlantic Power Corporation

 

Capital Power Income L.P.
200 Clarendon Street, Floor 25   10065 Jasper Avenue
Boston, Massachusetts 02116   Edmonton, Alberta T5J 3B1
Attn: Investor Relations   Attn: Investor Relations
617-977-2700   780-392-5105

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SUMMARY

        This summary highlights information contained elsewhere in this joint proxy statement and may not contain all the information that is important to you. Atlantic Power and CPILP urge you to read carefully the remainder of this joint proxy statement, including the annexes, the exhibits, the documents incorporated by reference and the other documents to which we have referred you because this summary does not provide all the information that might be important to you with respect to the Plan of Arrangement and the other matters being considered at the Atlantic Power and CPILP special meetings. See also the section entitled "Where You Can Find More Information" beginning on page 150.

The Entities

        Atlantic Power owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Atlantic Power's generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements ("PPA"), which seek to minimize exposure to changes in commodity prices. Atlantic Power's power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 MW, in which Atlantic Power's ownership interest is approximately 871 MW. Atlantic Power's current portfolio consists of interests in 12 operational power generation projects across nine states, one 53 MW biomass project under construction in Georgia, and an 84-mile, 500 kilovolt electric transmission line located in California. Atlantic Power also owns a majority interest in Rollcast Energy, Inc., a biomass power plant developer with several projects under development. Atlantic Power's common shares trade on the NYSE under the symbol "AT" and on the TSX under the symbol "ATP." Atlantic Power's headquarters are located at 200 Clarendon Street, Floor 25, Boston, Massachusetts, USA 02116, telephone number 617-977-2400. Atlantic Power's registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia, Canada V6C 2G8.

        CPILP's primary business is the ownership and operation of power plants in Canada and the United States, which generate electricity and steam, from which it derives its earnings and cash flows. The power plants generate electricity and steam from a combination of natural gas, waste heat, wood waste, water flow, coal and tire-derived fuel. CPILP's generation projects sell electricity to utilities and other large commercial customers under long-term PPAs, which seek to minimize exposure to changes in commodity prices. At present, CPILP's portfolio consists of 19 wholly-owned power generation assets located in both Canada (in the provinces of British Columbia and Ontario) and the United States (in the states of California, Colorado, Illinois, New Jersey, New York and North Carolina), a 50.15% interest in a power generation asset in Washington State, and a 14.3% common equity interest in Primary Energy Recycling Holdings LLC. CPILP's assets have a total net generating capacity of 1,400 MW and more than four million pounds per hour of thermal energy. The CPILP units trade on the TSX under the symbol "CPA.UN." The head office of CPILP is located at 10065 Jasper Avenue, Edmonton, Alberta, T5J 3B1. The registered office of CPILP is 200 University Avenue, Toronto, Ontario, M5H 3C6, telephone number 1-866-896-4636.

        CPI Income Services Ltd. (the "General Partner") is responsible for the management of CPILP. Pursuant to CPILP's partnership agreement, the General Partner is prohibited from undertaking any business activity other than acting as general partner of CPILP. The head and registered office of the General Partner is located at 10065 Jasper Avenue, Edmonton, Alberta, T5J 3B1, telephone number 1-866-896-4636. The General Partner has engaged CP Regional Power Services Limited Partnership and Capital Power Operations (USA) Inc. (together, the "Manager"), both subsidiaries of

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Capital Power, to perform management and administrative services for CPILP and to operate and maintain CPILP's power plants pursuant to certain management and operations agreements. The management and operations agreements will be terminated and/or assigned in connection with the Plan of Arrangement in consideration for the payment of an aggregate of C$10.0 million. See "Summary of the Arrangement Agreement—Summaries of Other Agreements Relating to the Arrangement—Management Agreements Termination Agreement and Management Agreement Assignment Agreement" beginning on page 106.

        CPI Investments is a holding company that owns, directly and indirectly, approximately 29.18% of the CPILP units and 100% of the shares of the General Partner. Capital Power L.P. ("Capital Power LP") owns a 49% voting interest and a 100% economic interest in CPI Investments and EPCOR owns the other 51% voting interest in CPI Investments. CPI Investments was incorporated on February 12, 2009 under the CBCA. The head and registered office of CPI Investments is located at TD Tower, 5th Floor, 10088-102 Avenue, Edmonton, Alberta, Canada, T5J 2Z1, telephone number 1-866-896-4636.

The Arrangement Agreement and Plan of Arrangement (see page 48)

        On June 20, 2011, Atlantic Power, CPILP, the General Partner and CPI Investments entered into the Arrangement Agreement, which provides that Atlantic Power will acquire, directly or indirectly, all of the issued and outstanding CPILP units pursuant to the Plan of Arrangement under the CBCA. Under the terms of the Plan of Arrangement, CPILP unitholders will be permitted to exchange each of their CPILP units for, at their election, C$19.40 in cash or 1.3 Atlantic Power common shares. All cash elections will be subject to proration if total cash elections exceed approximately C$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares.

        Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power, for approximately C$121.4 million. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power and CPILP and certain of its subsidiaries will be terminated (or assigned) in consideration of a payment of C$10.0 million. Atlantic Power or its subsidiaries will assume the management of CPILP and intends to enter into a transitional services agreement with Capital Power for a term of up to 12 months following the completion of the Plan of Arrangement, in respect of certain services, which will facilitate the integration of CPILP into Atlantic Power.

        The Arrangement Agreement contains customary representations, warranties and covenants. Among these covenants, CPILP and CPI Income Services Ltd. have each agreed not to solicit alternative transactions, except that CPILP may respond to an alternative transaction proposal that constitutes, or would reasonably be expected to lead to, a superior proposal. In addition, Atlantic Power or CPILP may be required to pay a C$35.0 million fee if the Arrangement Agreement is terminated in certain circumstances.

        The completion of the Plan of Arrangement is subject to the receipt of all necessary court and regulatory approvals in Canada and the United States and certain other closing conditions. Atlantic Power and CPILP currently expect to complete the Plan of Arrangement in the fourth quarter of 2011, subject to receipt of required shareholder/unitholder, court and regulatory approvals and the satisfaction or waiver of the financing and other conditions to the Plan of Arrangement described in the Arrangement Agreement.

        The full text of the Arrangement Agreement is attached as Annex A to this joint proxy statement. Atlantic Power and CPILP urge you to read it carefully.

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        On June 19, 2011, at a meeting of the Atlantic Power board of directors, by unanimous vote, the Atlantic Power board of directors determined that the Arrangement, including the issuance of Atlantic Power common shares to CPILP unitholders necessary to complete the Arrangement, is in the best interests of Atlantic Power and is fair to the stakeholders of Atlantic Power. In reaching these determinations, the Atlantic Power board of directors consulted with Atlantic Power's management and its legal, financial and other advisors, and also considered numerous factors, including strategic and financial benefits of the Arrangement and other factors which the Atlantic Power board of directors viewed as supporting its decisions.

        The strategic benefits that the Atlantic Power board of directors believes should result from the combination of Atlantic Power and CPILP include, among other things, the following:

        The financial benefits that the Atlantic Power board of directors believes should result from the combination of Atlantic Power and CPILP include, among other things, the following:

        At a meeting held on June 19, 2011, the members of the board of directors of the General Partner entitled to vote, being the independent directors of the General Partner, determined unanimously that the Arrangement is in the best interests of CPILP and is fair to the CPILP unitholders and resolved unanimously to recommend to the CPILP unitholders that they vote in favor of the Arrangement. In reaching these decisions, the board of directors of the General Partner consulted with its management and financial, legal and other advisors, and considered a variety of factors weighing in favor of or relevant to the Plan of Arrangement, including strategic and financial benefits of the Plan of Arrangement and other factors which the board of directors of the General Partner viewed as supporting its decisions.

        The strategic benefits that the board of directors of the General Partner believes should result from the combination of Atlantic Power and CPILP include, among other things, the following:

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        The financial benefits that the board of directors of the General Partner believes should result from the combination of Atlantic Power and CPILP include, among other things, the following:

        The other benefits that the board of directors of the General Partner believes should result from the combination of Atlantic Power and CPILP include, among other things, the following:

        At a meeting held on June 19, 2011, after considering the various factors and considerations further disclosed in the section titled "The Arrangement Agreement and Plan of Arrangement—Atlantic Power's Reasons for the Arrangement Agreement; Recommendations of Atlantic Power's Board of Directors" Atlantic Power's board of directors unanimously determined that the Plan of Arrangement and the other transactions contemplated by the Arrangement Agreement, including the issuance of Atlantic Power common shares to CPILP unitholders necessary to complete the Plan of Arrangement, are in the best interests of Atlantic Power and is fair to its stakeholders. Accordingly, the Atlantic Power board of directors unanimously recommends that the Atlantic Power shareholders vote "FOR" the Share Issuance Resolution.

        At a meeting held on June 19, 2011, after considering, among other things, the oral opinions of CIBC and Greenhill & Co. Canada Ltd. ("Greenhill"), subsequently confirmed in writing, the full text of which are attached as Annexes D and E, respectively, of this joint proxy statement, the members of the board of directors of the General Partner entitled to vote determined unanimously that the Plan of Arrangement is in the best interests of CPILP and is fair to the CPILP unitholders and resolved unanimously to recommend to the CPILP unitholders that they vote in favor of the Plan of Arrangement. The members of the board of directors of the General Partner entitled to vote also unanimously approved the Plan of Arrangement and the execution and performance of the Arrangement Agreement. Accordingly, the board of directors of the General Partner unanimously recommends that the CPILP unitholders vote "FOR" the approval of the Arrangement Resolution.

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        In connection with the Arrangement Agreement, TD Securities Inc. ("TD Securities") and Morgan Stanley & Co. LLC ("Morgan Stanley") each delivered to Atlantic Power's board of directors its written opinion, dated June 19, 2011, that, on such date and based upon and subject to the various limitations, qualifications and assumptions set forth in each written opinion, the consideration to be paid by Atlantic Power to CPILP unitholders pursuant to the Arrangement Agreement was fair, from a financial point of view, to Atlantic Power. The full texts of these opinions are attached as Annexes B and C, respectively, to this joint proxy statement.

        You should read each opinion carefully in its entirety for a description of the assumptions made, the matters considered and limitations on the review undertaken. Each opinion is addressed to the board of directors of Atlantic Power, and addresses only the fairness from a financial point of view of the consideration to be paid by Atlantic Power to CPILP unitholders pursuant to the Arrangement Agreement. The opinions do not address any other aspect of the Plan of Arrangement and do not constitute a recommendation to the shareholders of Atlantic Power or unitholders of CPILP as to how to vote with respect to the Plan of Arrangement or any other matter. In addition, the opinions do not in any manner address the prices at which Atlantic Power common shares will trade following the consummation of the Plan of Arrangement or at any other time.

        In connection with the Arrangement Agreement, on June 19, 2011, the board of directors of the General Partner received written opinions from each of CIBC and Greenhill stating that, on such date and based upon and subject to the various limitations, qualifications and assumptions set forth in each written opinion, the consideration to be received by CPILP unitholders pursuant to the Arrangement Agreement was fair from a financial point of view to such CPILP unitholders (other than the General Partner, CPI Investments and Atlantic Power in respect of the Greenhill opinion, and other than Capital Power and its affiliates in respect of the CIBC opinion). The full texts of these opinions, which set forth, among other things, the assumptions made, procedures followed, matters considered and qualifications and limitations on the scope of the review undertaken, are attached as Annexes D and E, respectively, to this joint proxy statement. CIBC also provided its written opinion to the special committee of the board of directors of the General Partner and the independent director of the board of directors of CPI Preferred Equity Ltd. that the consideration to be received by CPI Preferred Equity Ltd. pursuant to the membership interest purchase agreement in respect of the North Carolina assets is fair, from a financial point of view, to CPI Preferred Equity Ltd.

        Certain of the directors and officers of the General Partner are also officers and/or directors of Capital Power and its affiliates and are not considered to be independent of CPILP within the meaning of applicable Canadian securities laws. Capital Power and its affiliates have interests in the Plan of Arrangement and certain other transactions to be completed in connection with the Plan of Arrangement that are different from, or in addition to, the interests of the other CPILP unitholders. See "Canadian Securities Law Matters" beginning on page 85.

        The board of directors of the General Partner was aware of and considered these interests, among other matters, in evaluating the Plan of Arrangement, and in recommending that CPILP unitholders vote in favor of the Arrangement Resolution. The members of the board of directors of the General Partner who are officers and/or directors of Capital Power and its affiliates did not participate in the vote to approve the Plan of Arrangement, as a result of the potential conflict of interest presented by their positions with Capital Power and its affiliates.

        The following table indicates, as of September 7, 2011, the number of CPILP units beneficially owned, directly or indirectly, or over which control or direction is exercised, by: (i) each director and

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officer of CPILP; (ii) each associate or affiliate of an insider of CPILP; (iii) each associate or affiliate of CPILP; (iv) each insider of CPILP (other than a director or officer of CPILP; and (v) each person acting jointly or in concert with CPILP, and the maximum amount of potential cash consideration payable to each pursuant to the Plan of Arrangement:

Name
  Position with CPILP   CPILP
Units
  Maximum
Amount of
Potential Cash
Consideration
 

Graham L. Brown

  Director         n/a  

Brian A. Felesky

  Director (Independent)     5,640   $ 109,416  

Allen R. Hagerman

  Director (Independent)     17,702   $ 343,419  

Francois L. Poirier

  Director (Independent)     3,100   $ 60,140  

Brian T. Vaasjo

  Chairman and Director     7,400   $ 143,560  

Rodney D. Wimer

  Director (Independent)         n/a  

James Oosterbaan

  Director         n/a  

Stuart A. Lee

  Director and President     3,536   $ 68,598  

B. Kathryn Chisholm

  General Counsel and Corporate Secretary     915   $ 17,751  

Peter D. Johanson

  Controller     400   $ 7,760  

Leah M. Fitzgerald

  Assistant Corporate Secretary         n/a  

Anthony Scozzafava

  Chief Financial Officer     2,050   $ 39,770  

Yale Loh

  Vice President, Treasurer         n/a  

Capital Power Corporation(1)

  Unitholder     16,513,504   $ 320,361,978  

(1)
Capital Power indirectly owns 49% of the voting interests and all of the economic interests in CPI Investments. EPCOR owns the remaining 51% voting interest in CPI Investments. CPI Investments owns 16,513,504 CPILP units. Under the Plan of Arrangement, Atlantic Power will acquire all of the outstanding shares of CPI Investments on effectively the same basis as the acquisition of CPILP units under the Plan of Arrangement.

        All current directors and officers of the General Partner will resign their positions in connection with the Plan of Arrangement.

        CPILP units currently trade on the TSX. After the Plan of Arrangement, Atlantic Power intends to delist the CPILP units from the TSX. The preferred shares of CPI Preferred Equity Ltd. will remain outstanding and listed on the TSX.

        Atlantic Power common shares currently trade on the TSX and NYSE. Atlantic Power will also apply to list Atlantic Power common shares issuable under the Plan of Arrangement on the NYSE and the TSX, and it is a condition to the completion of the Plan of Arrangement that Atlantic Power shall have obtained approval for these listings.

        In addition to certain regulatory approvals of the power generation regulatory authorities required in connection with the Plan of Arrangement, the Arrangement is subject to approval under the:

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        The Arrangement must also be approved by the Court of Queen's Bench of Alberta. The court will be asked to make an order approving the Arrangement and determine that the Arrangement is fair to the CPILP unitholders. CPILP and the General Partner will apply to the court for this order if the regulatory approvals described above have been obtained and the CPILP unitholders approve the Arrangement Resolution at the CPILP special meeting.

Summaries of Other Agreements Relating to the Arrangement

        As part of the Plan of Arrangement, Atlantic Power will acquire all of the outstanding shares of CPI Investments (an entity indirectly owned by Capital Power and EPCOR), the direct and indirect holder of 16,513,504 CPILP units, on effectively the same basis as the acquisition of CPILP units under the Plan of Arrangement. In order to confirm the commitment of each shareholder of CPI Investments to support the Plan of Arrangement, contemporaneously with the entering into of the Arrangement Agreement, Atlantic Power entered into two support agreements, one with EPCOR and the other with Capital Power and Capital Power LP, the entity through which Capital Power holds its shares of CPI Investments. Pursuant to the support agreements, each of Capital Power LP and EPCOR agreed to, among other things, (i) vote all of its shares of CPI Investments in favor of the Plan of Arrangement and any related matters to give legal effect to the Plan of Arrangement, (ii) vote all of its shares of CPI Investments against any resolutions or proposals that might reasonably be expected to impede, frustrate, delay or prevent the Plan of Arrangement, (iii) not sell, transfer, pledge or assign its shares of CPI Investments or enter into a voting agreement with respect to such shares, (iv) not exercise any rights or remedies to impede, frustrate, delay or prevent the Plan of Arrangement and (v) abide by certain non-solicitation covenants in respect of CPILP and CPI Investments.

        Pursuant to the support agreement among Atlantic Power, Capital Power LP and Capital Power, among other things, (i) Capital Power agreed to cause Capital Power LP to fulfill its obligations under the support agreement and not to make certain acquisition proposals in respect of CPILP or CPI Investments, (ii) Capital Power LP and CPI Investments made certain representations specific to the Plan of Arrangement, including with respect to the representations and warranties made by CPI Investments in the Arrangement Agreement and equipment and personal property owned by Capital Power LP and/or Capital Power and used in the operations of the CPILP or any of the CPILP's facilities and (iii) Capital Power LP agreed that for a period of 90 days commencing on the Effective Date, Capital Power LP will not, without the prior consent of Atlantic Power, offer, sell, pledge, grant any option to purchase, hedge, transfer, assign, make any short sale or otherwise dispose of any Atlantic Power common shares received pursuant to the Plan of Arrangement (or agree to, or announce, any intention to do so) with certain limited customary exceptions. For a further discussion of the support agreements, see "Summary of the Arrangement Agreement—Summaries of Other Agreements Relating to the Arrangement—Support Agreements."

        On June 20, 2011, certain subsidiaries of Capital Power entered into an agreement (the "Management Agreements Termination Agreement") with CPILP and certain of its subsidiaries pursuant to which the parties agreed to terminate each of the management and operations agreements between them, other than the Frederickson Agreement (as defined below), effective immediately upon completion of the Plan of Arrangement. In consideration for the termination of the management and operations agreements, CPILP and its subsidiaries agreed to pay to the subsidiaries of Capital Power an aggregate of C$8.5 million.

        On June 20, 2011, a subsidiary of Capital Power entered into an agreement with Atlantic Power and Frederickson Power L.P., a subsidiary of CPILP, pursuant to which the subsidiary of Capital Power

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agreed to assign its right, benefit, interest and obligation in, to and under the operations and maintenance agreement in respect of CPILP's Frederickson facility (the "Frederickson Agreement") to Atlantic Power. The assignment will be effective immediately upon completion of the Plan of Arrangement. In consideration for the assignment, Atlantic Power has agreed to pay C$1.5 million to the subsidiary of Capital Power. The assignment is conditional on, among other things, receipt of the consent of Puget Sound Energy, Inc., the counterparty to the Frederickson Agreement, to the assignment.

        On June 20, 2011, a subsidiary of Capital Power entered into a purchase and sale agreement with certain subsidiaries of CPILP, pursuant to which the subsidiary of Capital Power agreed to purchase and the subsidiaries of CPILP agreed to sell indirectly all of the membership interests in the limited liability company that owns CPILP's Roxboro and Southport power plants in North Carolina. The purchase price for the membership interests is approximately C$121.4 million. Closing of the purchase and sale will take place on the Effective Date. Closing of the purchase and sale will be conditional on, among other things, receipt of all necessary regulatory approvals and consents, including, without limitation, expiration or early termination of the applicable waiting periods under the Hart-Scott Rodino Antitrust Improvements Act of 1976 and prior authorization from the Federal Energy Regulatory Commission under Section 203 of the United States Federal Power Act.

        On June 20, 2011, Atlantic Power, Capital Power and Capital Power Operations (USA) Inc. ("CPO USA") entered into an employee hiring and lease assignment agreement pursuant to which Atlantic Power agreed to assume the employment of certain designated employees who perform functions related to CPILP's business. This agreement was necessitated by the fact that neither CPILP nor the General Partner has any employees. Persons performing the functions of employees of CPILP are currently employed by Capital Power and CPO USA rather than directly by CPILP. For further details regarding CPILP employees, see "Business of the Partnership—Employees of the Partnership" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement.

        Pursuant to the agreement, Atlantic Power will (i) be bound by the collective agreements currently in place for Capital Power's unionized employees and, (ii) for certain individuals whose employment is not governed by the collective agreements, Atlantic Power will make offers of employment on substantially the same (or better) terms and conditions of employment, in the aggregate, as are in effect on the date of the offer. Existing employee benefits provided by Capital Power will vest on closing of the Plan of Arrangement and be paid out by Capital Power. The agreement also contemplates the negotiation of the assignment of office leases for Capital Power's offices located in the cities of Richmond, B.C., Toronto, Ontario and Chicago, Illinois.

        On June 20, 2011, Atlantic Power and Capital Power entered into a Canadian pension transfer agreement pursuant to which Atlantic Power agreed to assume the pension plan assets and obligations from Capital Power related to the employees that it assumes pursuant to the employee hiring and lease assignment agreement described above.

        The agreement primarily relates to the Capital Power Pension Plan (which is a Canadian registered pension plan with both a defined benefit and defined contribution component). For further details regarding Capital Power's pension plan assets and obligations, see "Compensation Discussion and Analysis—Pension Programs" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement. The

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agreement provides that the assets associated with the pension plan obligations of the employees being transferred to Atlantic Power will be carved out of the Capital Power Pension Plan and transferred to a new plan to be established by Atlantic Power. The new pension plan for Atlantic Power will have equivalent terms to the Capital Power Pension Plan.

        If there is a deficiency in the Capital Power Pension Plan on a going concern basis at the time of closing of the Plan of Arrangement, Capital Power is required to pay Atlantic Power the amount of the deficiency related to the assumed employees (and if there is a surplus, Atlantic Power is required to make a payment to Capital Power). Currently, it is estimated that there is a deficiency of approximately C$2.0 million. Atlantic Power is required to establish savings plans that are substantially the same as certain group RRSPs provided by Capital Power. Capital Power and Atlantic Power will take all commercially reasonable steps to permit transferring employees with balances in Capital Power's Group RRSPs to transfer their assets to Atlantic Power's Group RRSPs.

The Atlantic Power Special Meeting

        The special meeting of Atlantic Power shareholders will be held at the King Edward Hotel,                , 37 King Street East, Toronto, Ontario on            , the                day of                , 2011 at the hour of             a.m. (Toronto time).

        At the Atlantic Power special meeting, Atlantic Power shareholders will be asked to vote on the following resolutions:

        Pursuant to the rules of the NYSE and TSX, securityholder approval is required in instances where the number of securities issued or issuable in payment of the purchase price in a transaction such as the Plan of Arrangement exceeds 20% (NYSE) or 25% (TSX) of the number of securities of the listed issuer which are outstanding, on a non-diluted basis. Because the Arrangement Agreement contemplates the issuance of Atlantic Power common shares in excess of these thresholds on a non-diluted basis, the rules of the NYSE and TSX require that Atlantic Power must obtain approval of the Share Issuance Resolution by the holders of a majority of the Atlantic Power common shares represented in person or by proxy at the Atlantic Power special meeting.

        As of the close of business on the date of this joint proxy statement, there were approximately 68.6 million outstanding Atlantic Power common shares. Pursuant to the Plan of Arrangement, Atlantic Power will issue approximately 31.5 million Atlantic Power common shares (equal to approximately 46% of Atlantic Power's current issued and outstanding common shares).

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        Only holders of Atlantic Power common shares at the close of business on              , 2011, the record date for the Atlantic Power special meeting, will be entitled to notice of, and to vote at, the Atlantic Power special meeting or any adjournments or postponements thereof. On the record date, there were outstanding a total of approximately              Atlantic Power common shares. Each outstanding Atlantic Power common share is entitled to one vote on the Share Issuance Resolution and any other matter properly coming before the Atlantic Power special meeting.

        The Share Issuance Resolution will be approved if a majority of the votes cast by Atlantic Power shareholders, either in person or by proxy at the Atlantic Power special meeting are voted in favor of the resolution.

        As of the close of business on the Atlantic Power record date, Atlantic Power's directors and executive officers and their affiliates beneficially owned and had the right to vote 0.36 million Atlantic Power common shares at the Atlantic Power special meeting, which represents approximately 0.01% of the Atlantic Power common shares entitled to vote at the Atlantic Power special meeting. Each of the directors and officers of Atlantic Power have indicated their intention to vote in favor of the Share Issuance Resolution.

        If you are an Atlantic Power shareholder and fail to vote or fail to instruct your broker, investment dealer or other intermediary to vote, it will have no effect on any of the Atlantic Power proposals, assuming a quorum is present.

The CPILP Special Meeting

        The special meeting of CPILP unitholders will be held at the            ,             on            , the             day of            , 2011 at the hour of         a.m. (Edmonton time).

        At the CPILP special meeting, CPILP unitholders will be asked to vote on the following resolutions:

        Only holders of CPILP units at the close of business on            , 2011, the record date for the CPILP special meeting, will be entitled to notice of, and to vote at, the CPILP special meeting or any adjournments or postponements thereof. On the record date, there were outstanding a total of

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56,597,899 CPILP units. Each outstanding CPILP unit is entitled to one vote on the Arrangement Resolution and any other matter properly coming before the CPILP special meeting.

        Pursuant to the Interim Order, the number of votes required to pass the Arrangement Resolution shall be not less than 662/3% of the votes cast by CPILP unitholders, either in person or by proxy, at the CPILP special meeting. In addition, the Arrangement Resolution must be approved by a simple majority of the votes cast by the CPILP unitholders present in person or by proxy at the CPILP special meeting, after excluding those votes required to be excluded pursuant to the minority approval provisions of MI 61-101, being the votes of "interested parties" and their related parties and joint actors, which includes the General Partner and CPI Investments. Notwithstanding the foregoing, the Arrangement Resolution authorizes the board of directors of the General Partner, without further notice to or approval of the CPILP unitholders, subject to the terms of the Plan of Arrangement and the Arrangement Agreement, to amend the Plan of Arrangement or the Arrangement Agreement or to decide not to proceed with the Plan of Arrangement at any time prior to the Plan of Arrangement becoming effective pursuant to the provisions of the CBCA.

        As of the close of business on the CPILP record date, CPILP's directors and executive officers and their affiliates beneficially owned and had the right to vote            CPILP units at the CPILP special meeting, which represents approximately        % of the CPILP units entitled to vote at the CPILP special meeting. It is expected that CPILP's directors and executive officers will vote in favor of the Arrangement Resolution.

        If you are a CPILP unitholder and fail to vote or fail to instruct your broker, investment dealer or other intermediary to vote, it will have no effect on any of the CPILP proposals, assuming a quorum is present.

        Each registered holder of CPILP units is required to validly complete and duly sign a Letter of Transmittal and Election Form and submit such documents, together with such holder's CPILP unit certificate(s), if any, to the Depositary in order to receive the consideration under the Plan of Arrangement. The details of the procedures for the deposit of CPILP unit certificates and the delivery by the Depositary of Atlantic Power common shares and cash are set out in the Letter of Transmittal and Election Form accompanying this joint proxy statement. If you hold your CPILP units through a nominee such as a broker or dealer, you should carefully follow any instructions provided to you by such nominee for making an election. CDS Clearing and Depositary Services Inc. is the only registered holder of CPILP units. All other holders should consult their broker, dealer or other nominee through which they hold CPILP units for instructions and assistance in making an election. Pursuant to the terms of the Arrangement Agreement and the Plan of Arrangement, CPILP unitholders are entitled to receive, at their election, for each CPILP unit held (i) C$19.40 in cash (the "Cash Consideration") or (ii) 1.3 Atlantic Power common shares (the "Share Consideration"), subject to the Aggregate Cash Maximum and the Aggregate Share Maximum (together the "Consideration").

        The Election Deadline to deposit such properly completed Letter of Transmittal and Election Form with the Depositary is 5:00 p.m. (Edmonton time) on the date that is three business days prior to the date of the CPILP special meeting. Assuming the CPILP special meeting is held on            , 2011, the Election Deadline will be 5:00 p.m. (Edmonton time) on             , 2011. CPILP unitholders who do

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not forward to the Depositary a validly completed and duly signed Letter of Transmittal and Election Form, together with their CPILP unit certificate(s), if any, will not receive the cash and/or Atlantic Power common shares, as applicable, to which they are otherwise entitled until such a deposit is made. Any CPILP unitholder who does not deposit a duly completed Letter of Transmittal and Election Form with the Depositary prior to the Election Deadline shall be deemed to have elected to receive the Share Consideration in respect of all of such holder's CPILP units.

        Any certificate which immediately prior to the Effective Time represented outstanding CPILP units that is not deposited with the Depositary together with all other instruments or documents required by the Plan of Arrangement on or prior to the sixth anniversary of the Effective Date will cease to represent a claim or interest of any kind or nature as a CPILP unitholder or as a shareholder of Atlantic Power. On such date, the cash and Atlantic Power common shares to which the former holder of the certificate referred to in the preceding sentence was ultimately entitled under the Plan of Arrangement will be deemed to have been donated, surrendered and forfeited for no consideration to Atlantic Power.

Appraisal/Dissent Rights (see page 47)

        The shareholders of Atlantic Power are not entitled to dissent rights in connection with the Share Issuance Resolution.

        The unitholders of CPILP are not entitled to dissent rights in connection with the Arrangement Resolution.

U.S. Securities Law Matters (see page 87)

        The common shares of Atlantic Power to be issued pursuant to the Plan of Arrangement will not be registered under the Securities Act of 1933, as amended (the "Securities Act"), or the securities laws of any state of the United States and will be issued in reliance upon the exemption from registration set forth in Section 3(a)(10) of the Securities Act. The common shares of Atlantic Power to be issued pursuant to the Plan of Arrangement will be freely transferable under U.S. federal securities laws, except for securities held by persons who are deemed to be "affiliates" of Atlantic Power following completion of the Plan of Arrangement.

Material Canadian Federal Income Tax Consequences (see page 108)

        CPILP unitholders will realize a taxable disposition of their CPILP units under the Plan of Arrangement. Eligible holders that receive Atlantic Power common shares pursuant to the Plan of Arrangement will be entitled to make a joint tax election with Atlantic Power under the Tax Act that will, depending on the circumstances of each particular CPILP unitholder, allow for a full or partial deferral of taxable gains that would otherwise be realized.

        Atlantic Power common shares will be considered "qualified investments" for registered retirement savings plans and other tax-exempt plans.

        The primary Canadian federal income tax considerations arising in respect of the Plan of Arrangement, as well as the procedure to be followed by CPILP unitholders intending to make a joint tax election, are described more fully below under the heading "Material Canadian Federal Income Tax Considerations".

Material U.S. Federal Income Tax Consequences (see page 112)

        CPILP does not permit non-residents of Canada (as determined for purposes of the Tax Act) to hold CPILP units. Persons who are not US Holders will not be subject to U.S. federal income tax with respect to their CPILP units or Atlantic Power common shares received in exchange therefor unless

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(1) such person's income with respect thereto is effectively connected with the conduct of a trade or business in the United States, or (2) such person is an individual who is present in the United States for 183 days or more during the taxable year and has a "tax home" in the United States. Even if a non-US Holder is subject to U.S. federal income tax under either test in the preceding sentence, such person may be eligible for relief from (or reduction to) any U.S. income tax under a tax treaty. See "Certain U.S. Federal Income Tax Considerations" beginning on page 112.

Atlantic Power Financing (see page 113)

        Atlantic Power intends to finance the cash portion of the purchase price to complete the Plan of Arrangement by issuing up to approximately C$200.0 million of equity and up to approximately C$425.0 million of debt through public and private offerings. However, in the event that such financing is not available on terms satisfactory to Atlantic Power, Atlantic Power has received the TLB Commitment Letter, evidencing the commitment of a Canadian chartered bank and another financial institution to structure, arrange, underwrite and syndicate a senior secured credit facility consisting of the Tranche B Facility in the amount of $625 million, subject to the terms and conditions set forth therein.

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Selected Historical Consolidated Financial Data of Atlantic Power

        The following table presents selected consolidated financial information for Atlantic Power. The annual historical information as of, and for the years ended, December 31, 2010, 2009 and 2008 has been derived from the audited consolidated financial statements appearing in Atlantic Power's Annual Report on Form 10-K for the year ended December 31, 2010, delivered together with, and/or incorporated by reference into this joint proxy statement. The annual historical information as of, and for the years ended, December 31, 2007 and 2006 has been derived from historical financial statements not delivered with, or incorporated by reference into, this joint proxy statement. The historical information as of, and for the six month periods ended, June 30, 2011 and 2010 has been derived from the unaudited consolidated financial statements appearing in Atlantic Power's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, delivered together with, and/or incorporated by reference into this joint proxy statement. Data for all periods have been prepared under U.S. GAAP. You should read the following selected consolidated financial data together with Atlantic Power's consolidated financial statements and the notes thereto and the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" included as part of Atlantic Power's Annual Report on Form 10-K for the year ended December 31, 2010 and Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, each of which has been delivered together with, and/or is incorporated by reference into this joint proxy statement. See "Where You Can Find More Information" beginning on page 150 of this joint proxy statement.

 
  Year Ended December 31,   Six months ended
June 30,
 
(in thousands of US dollars,
except as otherwise stated)

  2010   2009   2008   2007   2006(a)   2011(a)   2010(a)  

Project revenue

  $ 195,256   $ 179,517   $ 173,812   $ 113,257   $ 69,374   $ 106,923   $ 95,125  

Project income

    41,879     48,415     41,006     70,118     57,247     27,900     19,405  

Net (loss) income attributable to Atlantic Power Corporation

    (3,752 )   (38,486 )   48,101     (30,596 )   (2,408 )   19,322     (4,618 )

Basic earnings (loss) per share

  $ (0.06 ) $ (0.63 ) $ 0.78   $ (0.50 ) $ (0.05 ) $ 0.28   $ (0.08 )

Basic earnings (loss) per share, C$(b)

  $ (0.06 ) $ (0.72 ) $ 0.84   $ (0.53 ) $ (0.06 ) $ 0.28   $ (0.08 )

Diluted earnings (loss) per share(c)

  $ (0.06 ) $ (0.63 ) $ 0.73   $ (0.50 ) $ (0.05 ) $ 0.28   $ (0.08 )

Diluted earnings (loss) per share, C$(b)(c)

  $ (0.06 ) $ (0.72 ) $ 0.78   $ (0.53 ) $ (0.06 ) $ 0.28   $ (0.08 )

Distribution declared per subordinated note(d)

  $   $ 0.51   $ 0.60   $ 0.59   $ 0.57   $   $  

Dividend declared per common share

  $ 1.06   $ 0.46   $ 0.40   $ 0.40   $ 0.37   $ 0.57   $ 0.52  

Total assets

  $ 1,013,012   $ 869,576   $ 907,995   $ 880,751   $ 965,121   $ 1,008,980   $ 862,525  

Total long-term liabilities

  $ 518,273   $ 402,212   $ 654,499   $ 715,923   $ 613,423   $ 523,351   $ 407,413  

(a)
Unaudited.

(b)
The C$ amounts were converted using the average exchange rates for the applicable reporting periods.

(c)
Diluted earnings (loss) per share is computed including dilutive potential shares, which include those issuable upon conversion of convertible debentures and under Atlantic Power's long term incentive plan. Because Atlantic Power reported a loss during the years ended December 31, 2010, 2009, 2007 and 2006, and for the six month period ended June 30, 2010, the effect of including potentially dilutive shares in the calculation during those periods is anti-dilutive. Please see the notes to Atlantic Power's historical consolidated financial statements for information relating to the number of shares used in calculating basic and diluted earnings per share for the periods presented.

(d)
At the time of Atlantic Power's initial public offering, its publicly traded security was an income participating security, or an "IPS", each of which was comprised of one common share and C$5.767 principal amount of 11% subordinated notes due 2016. On November 27, 2009, Atlantic Power converted from the IPS structure to a traditional common share structure. In connection with the conversion, each IPS was exchanged for one new common share.

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Selected Historical Consolidated Financial Data of CPILP

        The following table presents selected consolidated financial information for CPILP. The selected historical financial data as of, and for the years ended, December 31, 2010, 2009 and 2008 has been derived from CPILP's audited consolidated financial statements for those periods appearing elsewhere in this joint proxy statement. The selected historical financial data as of, and for the years ended, December 31, 2007 and 2006 has been derived from the audited consolidated financial statements of CPILP not appearing in this joint proxy statement. The selected historical financial data as of, and for the six month periods ended, June 30, 2011 and 2010 are derived from CPILP's unaudited consolidated financial statements for those periods appearing elsewhere in this joint proxy statement.

        Data for all periods presented below have been prepared under Canadian generally accepted accounting principles and are reported in Canadian dollars. You should read the following selected consolidated financial data together with CPILP's consolidated financial statements and the notes thereto and the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" for CPILP included elsewhere in this joint proxy statement.

 
  Year Ended December 31,   Six months ended
June 30,
 
(in thousands of Canadian dollars,
except as otherwise stated)

  2010   2009   2008   2007   2006   2011(a)(b)   2010(a)  

  $     $     $     $     $     $     $    

Revenue

  $ 532,377   $ 586,491   $ 499,267   $ 549,872   $ 326,900   $ 261,524   $ 241,453  

Depreciation, amortization and accretion

  $ 98,227   $ 93,249   $ 88,313   $ 85,553   $ 65,200   $ 45,461   $ 49,806  

Financial charges and other, net

  $ 40,179   $ 46,462   $ 94,836   $ 8,574   $ 42,200   $ 21,457   $ 18,879  

Net income before tax and preferred share Dividends

  $ 35,224   $ 56,812   $ (91,918 ) $ 108,953   $ 67,400   $ 18,741   $ 2,988  

Net income (loss) attributable to equity holders of CPILP

  $ 30,500   $ 57,553   $ (67,893 ) $ 30,816   $ 62,121   $ 10,529   $ 5,335  

Basic and diluted earning (loss) per unit, C$

  $ 0.55   $ 1.07   $ (1.26 ) $ 0.59   $ 1.28   $ 0.19   $ 0.10  

Distributions declared per unit, C$

  $ 1.76   $ 1.95   $ 2.52   $ 2.52   $ 2.52   $ 0.88   $ 0.88  

Total assets

  $ 1,583,910   $ 1,668,057   $ 1,809,225   $ 1,852,573   $ 1,883,400   $ 1,471,772   $ 1,657,926  

Total long-term liabilities

  $ 874,190   $ 853,314   $ 935,248   $ 730,940   $ 757,800   $ 821,382   $ 883,863  

Operating margin

  $ 187,567   $ 211,680   $ 111,446   $ 216,188   $ 185,900   $ 99,675   $ 77,276  

(a)
Unaudited

(b)
Results for 2011 have been prepared using International Financial Reporting Standards.

        Under U.S. GAAP, the following differences are noted:

 
  Years Ended December 31,  
(in thousands of Canadian dollars,
except as otherwise stated)

  2010   2009  

Revenue

  $ 532,377   $ 586,491  

Depreciation, amortization and accretion

  $ 98,277   $ 93,249  

Financial charges and other, net

  $ 40,129   $ 46,462  

Net income before tax and preferred share dividends

  $ 39,179   $ 54,753  

Net income (loss) attributable to equity holders of CPILP

  $ 34,455   $ 55,529  

Basic and diluted earning (loss) per unit, C$

  $ 0.63   $ 1.03  

Distributions declared per unit, C$

  $ 1.76   $ 1.95  

Total assets

  $ 1,588,352   $ 1,673,059  

Total long-term liabilities

  $ 878,632   $ 858,317  

Operating margin

  $ 191,530   $ 209,621  

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Summary Unaudited Pro Forma Condensed Combined Consolidated Financial Information

        The following table sets forth selected information about the pro forma financial condition and results of operations, including per share data, of Atlantic Power after giving effect to the completion of Plan of Arrangement with CPILP. The table sets forth selected unaudited pro forma condensed combined consolidated statements of operations for the six months ended June 30, 2011 and the year ended December 31, 2010, as if the Plan of Arrangement had been completed on January 1, 2010, and the selected unaudited pro forma condensed combined consolidated balance sheet data as of June 30, 2011, as if the Plan of Arrangement had been completed on that date. The information presented below was derived from Atlantic Power's and CPILP's consolidated historical financial statements, and should be read in conjunction with these financial statements and the notes thereto, included elsewhere or delivered with, and/or incorporated by reference into this joint proxy statement and the other unaudited pro forma financial data, including related notes, included elsewhere in this joint proxy statement. CPILP's historical consolidated financial statements have been prepared in accordance with Canadian GAAP and include a discussion of the significant differences between Canadian GAAP and U.S. GAAP in Note 27 to the CPILP audited consolidated financial statements for the year ended December 31, 2010. For purposes of the unaudited pro forma condensed combined financial data, CPILP's balance sheet financial data has been translated from Canadian Dollars into U.S. Dollars using a C$/$ exchange rate of C$0.9643 to $1.00 and is presented in accordance with U.S. GAAP. CPILP's statement of operations financial data has been translated from Canadian dollars into U.S. dollars using an average C$/$ exchange rate of C$0.9766 to $1.00 and C$1.0295 to $1.00 for the six months ended June 30, 2011 and the year ended December 31, 2010, respectively, and is presented in accordance with U.S. GAAP.

        The unaudited pro forma financial data is based on estimates and assumptions that are preliminary and does not purport to represent the financial position or results of operations that would actually have occurred had the Plan of Arrangement been completed as of the dates or at the beginning of the periods presented or what the Combined Company's results will be for any future date or any future period. See the sections entitled "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors".


Unaudited Pro Forma Condensed Combined Consolidated Financial Information

(in thousands of U.S. dollars, except per share data)
  Six Months
Ended
June 30, 2011
  Year Ended
December 31, 2010
 

Combined Consolidated Statement of Operations Information

             

Project revenues

  $ 346,015   $ 669,985  

Project income

    60,937     91,687  

Net income

    19,817     11,135  

Noncontrolling interest

    6,952     13,597  

Net income (loss) attributable to Atlantic Power Corporation/CPILP

    12,865     (2,462) (1)

Earnings (loss) per share

             
 

Basic

  $ 0.11   $ (0.02 )
 

Diluted

  $ 0.11   $ (0.02 )

Weighted average shares outstanding

             
 

Basic

    112,757     106,347  
 

Diluted

    113,184     106,347  

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(in thousands of U.S. dollars)
  As of
June 30, 2011
 

Balance sheet information

       

Cash and cash equivalents

  $ 145,409  

Total assets

    3,456,478  

Long-term debt and convertible debentures

    1,602,699  

Total liabilities

    2,096,958  
       

Total Atlantic Power Corporation shareholders' equity

    1,128,671  

Noncontrolling interest

    230,849  
       

Total equity

  $ 1,359,520  

(1)
Net income (loss) attributable to Atlantic Power/CPILP on a pro forma basis reflects:

a.
a significant increase in amortization expense as a result of the estimated increase in fair value associated with CPILP PPA's (see Note 5(e) in the notes to the unaudited condensed combined consolidated financial statements);

b.
timing differences in Atlantic Power's deferred tax expense; and

c.
timing differences in CPILP's deferred tax benefit.

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Selected Comparative Per Share/Unit Market Price and Dividend Information

        Atlantic Power's common shares are listed and traded on the NYSE under the symbol "AT" and on the TSX under the symbol "ATP". CPILP's units are listed and traded on the TSX under the symbol "CPA.UN". The following table sets forth, for the quarters indicated, the high and low sales price per share of Atlantic Power's common shares as reported on both the NYSE and the TSX and the high and low sales price per CPILP unit as reported on the TSX. In addition, the table sets forth the monthly cash dividends per share declared by Atlantic Power with respect to its common shares and the monthly cash distribution per unit declared by CPILP with respect to its limited partnership units. On the Atlantic Power record date (                         , 2011), there were approximately                        million common shares of Atlantic Power outstanding. On the CPILP record date (                        , 2011), there were 56,597,899 CPILP units outstanding.

 
  Atlantic Power (TSX)   CPILP(TSX)  
 
  High
(C$)
  Low
(C$)
  Dividends
Declared
  High   Low   Distribution
Declared
 

2009

                                     
 

First Quarter

  $ 9.28   $ 6.34     0.2735     18.98     12.90     0.63  
 

Second Quarter

    9.45     7.71     0.2735     16.21     11.65     0.44  
 

Third Quarter

    9.49     8.55     0.2735     16.30     13.62     0.44  
 

Fourth Quarter

    11.90     9.08     0.2735     15.77     13.35     0.44  

2010

                                     
 

First Quarter

    13.85     11.50     0.2735     18.43     15.54     0.44  
 

Second Quarter

    12.90     11.20     0.2735     18.14     15.05     0.44  
 

Third Quarter

    14.47     12.11     0.2735     18.85     16.03     0.44  
 

Fourth Quarter

    15.18     13.31     0.2735     19.02     17.11     0.44  

2011

                                     
 

First Quarter

    15.50     14.41     0.2735     21.22     17.65     0.44  
 

Second Quarter

    15.72     13.82     0.2735     21.05     18.28     0.44  
 

Third Quarter (until September 7, 2011)

    15.46     12.92     0.1824     19.50     17.23     0.44  

 

 
  Atlantic Power (NYSE)  
 
  High ($)   Low ($)   Dividends
Declared
 

2010

                   
 

Third Quarter (beginning July 23, 2010)

  $ 14.00   $ 12.10     0.266  
 

Fourth Quarter

    14.98     13.26     0.270  

2011

                   
 

First Quarter

    15.75     14.72     0.277  
 

Second Quarter

    16.18     14.33     0.280  
 

Third Quarter (until September 7, 2011)

    16.34     13.12     0.189  

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Certain Historical and Pro Forma Per Share/Unit Data

        The following tables set forth certain historical, pro forma and pro forma equivalent per share financial information for Atlantic Power common shares and per unit financial information for CPILP units. The pro forma and pro forma equivalent per share/unit information gives effect to the Plan of Arrangement as if the Plan of Arrangement had occurred on June 30, 2011 in the case of book value per share data and as of January 1, 2010 in the case of net income per share/unit data.

        The pro forma per share/unit balance sheet information combines CPILP's June 30, 2011 unaudited consolidated balance sheet with Atlantic Power's June 30, 2011 unaudited consolidated balance sheet. The pro forma per share/unit income statement information for the fiscal year ended December 31, 2010, combines CPILP's audited consolidated statement of income for the fiscal year ended December 31, 2010, with Atlantic Power's audited consolidated statement of operations for the fiscal year ended December 31, 2010. The pro forma per share/unit income statement information for the six months ended June 30, 2011, combines CPILP's unaudited consolidated statement of income for the six months ended June 30, 2011, with Atlantic Power's unaudited consolidated statement of operations for the six months ended June 30, 2011. The CPILP pro forma equivalent per share/unit financial information is calculated by multiplying the unaudited Atlantic Power pro forma combined per share/unit amounts by 1.3 (being the exchange ratio under the Plan of Arrangement). The balance sheet of CPILP as of June 30, 2011 has been translated using a C$/$ exchange rate of C$0.9643 to $1.00.

        The per share data for the Combined Company on a pro forma basis presented below is not necessarily indicative of the financial condition of the Combined Company had the Plan of Arrangement been completed on June 30, 2011 and the operating results that would have been achieved by the Combined Company had the Plan of Arrangement been completed as of the beginning of the period presented, and should not be construed as representative of the Combined Company's future financial condition or operating results. The per share data for the Combined Company on a pro forma basis presented below has been derived from the unaudited pro forma condensed combined consolidated financial data of the Combined Company included in this joint proxy statement. In addition, the unaudited pro forma information does not purport to indicate balance sheet data or results of operations data as of any future date or for any future period.

 
  As of and for the
Six Months Ended
June 30, 2011
  As of and for the
Year Ended
December 31, 2010
 

Atlantic Power Historical Data per Common Share

             
 

Income from continuing operations

             
   

Basic

  $ 0.28   $ (0.06 )
   

Diluted

  $ 0.28   $ (0.06 )
 

Dividends declared per Common Share

  $ 0.57   $ 1.06  
 

Book value per Common Share

  $ 6.33   $ 7.02  

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  As of and for the
Six Months Ended
June 30, 2011(a)
  As of and for the
Year Ended
December 31, 2010(b)
 

CPILP Historical Data per Unit(a)

             
 

Income from continuing operations attributable to controlling interest

             
   

Basic

  $ 0.19   $ 0.55  
   

Diluted

  $ 0.19   $ 0.55  
 

Distributions declared per unit

  $ 0.88   $ 1.76  
 

Book value per unit

  $ 5.87   $ 7.30  

(a)
Results for 2011 have been prepared using International Financial Reporting Standards.

(b)
Results for 2010 have been prepared using Canadian GAAP.

 
  As of and for the
Six Months Ended
June 30, 2011
  As of and for the
Year Ended
December 31, 2010
 

Atlantic Power Pro Forma Combined Data per Common Share

             
 

Income from continuing operations

             
   

Basic

  $ 0.11   $ (0.02 )
   

Diluted

  $ 0.11   $ (0.02 )
 

Dividends declared per Common Share

  $ 0.58   $ 1.12  
 

Book value per Common Share

  $ 12.00   $ 13.28  

 

 
  As of and for the
Six Months Ended
June 30, 2011
  As of and for the
Year Ended
December 31, 2010
 

CPILP Pro Forma Equivalent Combined Data per unit

             
 

Income from continuing operations attributable to controlling interest

             
   

Basic

  $ 0.14   $ (0.03 )
   

Diluted

  $ 0.14   $ (0.03 )
 

Distributions declared per unit

  $ 0.75   $ 1.46  
 

Book value per unit

  $ 15.60   $ 17.26  

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Exchange Rate Information

        The following table sets forth, for each period indicated, the high and low exchange rates for one U.S. dollar, expressed in Canadian dollars, the average of such exchange rates on the last day of each month during such period and the exchange rate at the end of such period, based on the noon buying rate as quoted by the Bank of Canada. On September 7, 2011, the noon buying rate was $1.00 = C$0.9883.

 
  Six Months Ended
June 30,
  Twelve Months Ended
December 31,
 
 
  2011   2010   2010   2009   2008   2007   2006  

High

  C$ 1.0022   C$ 1.0778   C$ 1.0778   C$ 1.3000   C$ 1.2969   C$ 1.1853   C$ 1.1726  

Low

  C$ 0.9486   C$ 0.9961   C$ 0.9946   C$ 1.0292   C$ 0.9719   C$ 0.9170   C$ 1.0990  

Average

  C$ 0.9769   C$ 1.0338   C$ 1.0299   C$ 1.1420   C$ 1.0660   C$ 1.0748   C$ 1.1341  

Period End

  C$ 0.9643   C$ 1.0606   C$ 0.9946   C$ 1.0466   C$ 1.2246   C$ 1.0120   C$ 1.1653  

Source: Bank of Canada

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RISK FACTORS

        In addition to the other information included and incorporated by reference into this joint proxy statement, including the matters addressed in the section entitled "Cautionary Note Regarding Forward-Looking Statements," you should carefully consider the following risks before deciding whether to vote for the Share Issuance Resolution, in the case of Atlantic Power shareholders, or the Arrangement Resolution, in the case of CPILP unitholders. In addition, you should read and consider Atlantic Power's Annual Report on Form 10-K for the year ended December 31, 2010, as updated by subsequent Quarterly Reports on Form 10-Q, all of which are filed with the SEC and have been delivered with, and/or incorporated by reference into this joint proxy statement. See "Where You Can Find More Information" beginning on page 150.

Risk Factors Relating to the Plan of Arrangement

The exchange ratio is fixed and will not be adjusted in the event of any change in either CPILP's unit price or Atlantic Power's share price.

        Under the Plan of Arrangement, for each CPILP unit held, CPILP unitholders will be entitled to elect to receive either C$19.40 in cash or 1.3 Atlantic Power common shares, subject to proration. This exchange ratio is fixed in the Plan of Arrangement and will not be adjusted for changes in the market price of either CPILP units or Atlantic Power shares. Changes in the price of Atlantic Power's shares prior to completion of the Plan of Arrangement may affect the market value that CPILP unitholders will receive on the date of the effective time for the Plan of Arrangement. Share price changes may result from a variety of factors (many of which are beyond Atlantic Power's or Capital Power's control).

Because the Plan of Arrangement will be completed after the date of the special meetings, at the time of the applicable special meeting, you will not know the exact market value of the Atlantic Power shares that CPILP unitholders will receive upon completion of the Plan of Arrangement.

        If the price of Atlantic Power common shares increases between the time of the special meetings and the effective time of the Plan of Arrangement, CPILP unitholders will receive Atlantic Power common shares that have a market value that is greater than the market value of such shares at the time of the special meetings. If the price of Atlantic Power common shares decreases between the time of the special meetings and the effective time of the Plan of Arrangement, CPILP unitholders will receive Atlantic Power common shares that have a market value that is less than the market value of such shares at the time of the special meetings. Therefore, because the exchange ratio is fixed, Atlantic Power shareholders and CPILP unitholders cannot be sure at the time of the special meetings of the market value of the share consideration that will be paid to CPILP unitholders upon completion of the Plan of Arrangement.

Failure to complete the Plan of Arrangement could negatively impact the share or unit prices and the future business and financial results of Atlantic Power and CPILP.

        If the Plan of Arrangement is not completed, the ongoing businesses of Atlantic Power and CPILP may be adversely affected. If the Plan of Arrangement is not completed, CPILP will have to consider alternative transactions, including the internalization of management. Additionally, if the Plan of Arrangement is not completed and the Arrangement Agreement is terminated, either Atlantic Power or CPILP, as the case may be, may be required to pay to the other a break-up fee under the Arrangement Agreement in the amount of C$35.0 million. The foregoing risks, or other risks arising in connection with the failure of the Plan of Arrangement, including the diversion of management attention from conducting the business of the respective entity and pursuing other opportunities during the pendency of the Plan of Arrangement, may have an adverse effect on the business, operations, financial results and share or unit prices of Atlantic Power and CPILP.

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The Arrangement Agreement contains provisions that could discourage a potential competing acquirer of CPILP.

        The Arrangement Agreement contains "no shop" provisions that, subject to limited exceptions, restrict CPILP's and the General Partner's ability to solicit, encourage, facilitate or discuss competing third-party proposals to acquire units or assets of CPILP. In certain specified circumstances, one of the parties will be required to pay a break-up fee of C$35.0 million to the other party. See "Summary of the Arrangement Agreement—Covenants—Non-Solicitation" on page 100 and "—Termination of the Arrangement Agreement—Termination Payment" beginning on page 103.

        These provisions could discourage a potential competing acquirer that might have an interest in acquiring all or a significant part of CPILP from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share or unit cash or market value than the market value proposed to be received or realized in the Plan of Arrangement, or might result in a potential competing acquirer proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the C$35.0 million termination fee that may become payable in certain circumstances.

In certain circumstances, if the Arrangement Agreement is terminated without any payment of a termination payment, Atlantic Power or CPILP may be required to make an expense reimbursement payment to the other party.

        Under the Arrangement Agreement, CPILP would be required to make an expense reimbursement payment to Atlantic Power, up to a maximum of C$8.0 million, in the event the Arrangement Agreement is terminated in certain circumstances, including, but not limited to, if the CPILP unitholders do not approve the Arrangement Resolution at the CPILP special meeting.

        Under the Arrangement Agreement, Atlantic Power would be required to make an expense reimbursement payment to CPILP, up to a maximum of C$8.0 million, in the event the Arrangement Agreement is terminated in certain circumstances, including, but not limited to, if the Atlantic Power shareholders do not approve the Share Issuance Resolution at the Atlantic Power special meeting.

        If the Arrangement Agreement is terminated and either Atlantic Power or CPILP determines to seek another business combination, it may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the Plan of Arrangement.

If the financing for the transactions contemplated by the Arrangement Agreement becomes unavailable, the Plan of Arrangement may not be completed.

        Atlantic Power intends to finance the cash portion of the purchase price to complete the Plan of Arrangement by issuing up to approximately C$200.0 million of equity and up to approximately C$425.0 million of debt through public and private offerings. However, in the event that such financing is not available on terms satisfactory to Atlantic Power, Atlantic Power has received the written commitment of a Canadian chartered bank and another financial institution to structure, arrange, underwrite and syndicate the Tranche B Facility, being a senior secured credit facility in the amount of $625 million. Funding under the Tranche B Facility is subject to certain conditions, including, without limitation, that there shall not have occurred a Material Adverse Effect (as defined in the Arrangement Agreement) in respect of Atlantic Power, CPILP, the General Partner and CPI Investments taken as a whole. In the event that the lenders under the Tranche B Facility fail to provide funding, Atlantic Power may not be able to complete the Plan of Arrangement and may be subject to a termination fee of C$35.0 million.

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Obtaining required governmental and court approvals necessary to satisfy closing conditions may delay or prevent completion of the Plan of Arrangement.

        Completion of the Plan of Arrangement is conditioned upon the receipt of certain governmental authorizations, consents, orders or other approvals, including but not limited to approval under the Investment Canada Act, the Competition Act (Canada), the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (United States) and the United States Federal Power Act. The Plan of Arrangement must also be approved by the Court of Queen's Bench of Alberta. No assurance can be given that the approvals not obtained to date will be obtained, and, even if such approvals are obtained, no assurance can be given as to the terms, conditions and timing of the approvals or that they will satisfy the terms of the Arrangement Agreement. See Summary of the Arrangement Agreement—Conditions Precedent to the Plan of Arrangement" beginning on page 94 for a discussion of the conditions to the completion of the Plan of Arrangement and "The Arrangement Agreement and Plan of Arrangement—Regulatory Approvals Required for the Plan of Arrangement and Other Regulatory Matters" beginning on page 88 for a description of the regulatory approvals necessary in connection with the Plan of Arrangement.

Risk Factors Relating to the Combined Company Following the Plan of Arrangement

The failure to integrate successfully the businesses of Atlantic Power and CPILP in the expected timeframe would adversely affect the Combined Company's future results.

        The success of the Plan of Arrangement will depend, in large part, on the ability of the Combined Company to realize the anticipated benefits, including cost savings, from combining the businesses of Atlantic Power and CPILP. To realize these anticipated benefits, the businesses of Atlantic Power and CPILP must be successfully integrated. This integration will be complex and time-consuming. The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in the Combined Company not fully achieving the anticipated benefits of the Plan of Arrangement.

        Potential difficulties that may be encountered in the integration process include the following:

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The growth plans of the Combined Company are dependent on future acquisitions and growth opportunities that may not be realized.

        The ability to expand through acquisitions and growth opportunities is integral to the Combined Company's business strategy and requires that it identifies and consummates suitable acquisition or investment opportunities that meet its investment criteria and are compatible with its growth strategy. The Combined Company may not be successful in identifying and consummating acquisitions or investments that meet its investment criteria on satisfactory terms or at all. The failure to identify and consummate suitable acquisitions, to take advantage of other investment opportunities, or to integrate successfully any acquisitions without substantial expense, delay or other operational or financial problems, would impede the Combined Company's growth and negatively affect its results of operations and cash available for distribution to its shareholders.

Increased debt and debt service obligations may adversely affect the Combined Company.

        Atlantic Power intends to finance the cash portion of the purchase price to complete the Plan of Arrangement by issuing up to approximately C$200.0 million of equity and up to approximately C$425.0 million of debt through public and private offerings. However, in the event Atlantic Power is unable to successfully complete such offerings, it may need to borrow up to approximately $625.0 million pursuant to a senior secured term loan facility. Such facility will be guaranteed by Atlantic Power and each of its existing and subsequently acquired or organized direct or indirect subsidiaries (excluding CPILP and each of its subsidiaries), and to contain covenants restricting certain actions by Atlantic Power and its subsidiaries (including CPILP and its subsidiaries), including financial, affirmative and negative covenants, which may include limitations on the ability to incur indebtedness, create liens and merge and consolidate with other companies, in each case, subject to exceptions and baskets that may be mutually agreed upon by Atlantic Power and the lender parties thereto, the exact terms of which will be negotiated before the effective time for the Plan of Arrangement.

        After the Plan of Arrangement, the Combined Company will have an increased amount of indebtedness. On a pro forma basis assuming the Plan of Arrangement was consummated on                 , the Combined Company would have had                of indebtedness. The Combined Company may also obtain additional long-term debt and working capital lines of credit to meet future financing needs, subject to certain restrictions under its existing indebtedness, which would increase its total debt.

        The potential significant negative consequences on the Combined Company's financial condition and results of operations that could result from its increased amount of debt include:

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A downgrade in Atlantic Power's or CPILP's credit ratings or any deterioration in their credit quality could negatively affect the Combined Company's ability to access capital and its ability to hedge and could trigger termination rights under certain contracts.

        A downgrade in Atlantic Power's or CPILP's credit ratings or deterioration in their credit quality could adversely affect the Combined Company's ability to renew existing, or obtain access to new, credit facilities and could increase the cost of such facilities and trigger termination rights or enhanced disclosure requirements under certain contracts to which CPILP is a party. Any downgrade of CPILP's corporate credit rating could cause counterparties and financial derivative markets to require CPILP to post letters of credit or other collateral, make cash prepayments, obtain a guarantee agreement or provide other security, all of which would expose CPILP to additional costs.

The Plan of Arrangement, if completed, will dilute the the ownership position of Atlantic Power's current common shareholders in the Combined Company.

        If the Plan of Arrangement is completed, Atlantic Power would issue approximately 31.5 million common shares in connection with the Plan of Arrangement, representing approximately 31.49% of its outstanding common shares after giving effect to the Plan of Arrangement (based on the number of Atlantic Power common shares outstanding on June 20, 2011, being the date of the Arrangement Agreement, and excluding any common shares that may be issued to finance the cash portion of the purchase price under the Plan of Arrangement). Consequently, following the Plan of Arrangement, Atlantic Power's current shareholders, as a general matter, would have less influence over the management and policies of the Combined Company than they currently exercise over the management and policies of Atlantic Power.

The Combined Company's results of operations may differ significantly from the unaudited pro forma condensed combined financial data included in this joint proxy statement.

        This joint proxy statement includes unaudited pro forma condensed combined financial statements to illustrate the effects of the Plan of Arrangement on Atlantic Power's historical financial position and operating results. The unaudited pro forma condensed combined statements of income for the fiscal year ended December 31, 2010 and for the six months ended June 30, 2011 combine the historical consolidated statements of income of Atlantic Power and CPILP, giving effect to the Plan of Arrangement, as if it had occurred on January 1, 2010. The unaudited pro forma condensed combined balance sheet as of June 30, 2011 combines the historical consolidated balance sheets of Atlantic Power and CPILP, giving effect to the Plan of Arrangement as if it had occurred on June 30, 2011. This unaudited pro forma financial data is presented for illustrative purposes only and does not necessarily indicate the results of operations or the combined financial position that would have resulted had the Plan of Arrangement been completed as of the dates or at the beginning of the periods presented, as applicable, nor is it indicative of the results of operations in future periods or the future financial position of the Combined Company.

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The Combined Company is expected to incur significant expenses related to the integration of Atlantic Power and CPILP.

        The Combined Company is expected to incur significant expenses in connection with the Plan of Arrangement and the integration of Atlantic Power and CPILP. There are a large number of processes, policies, procedures, operations, technologies and systems that must be integrated. While Atlantic Power and CPILP have assumed that a certain level of expenses will be incurred, there are many factors beyond their control that could affect the total amount or the timing of the integration expenses. Moreover, many of the expenses that will be incurred are, by their nature, difficult to estimate accurately. These integration expenses likely will result in the Combined Company taking significant charges against earnings following the completion of the Plan of Arrangement, and the amount and timing of such charges are uncertain at present.

If goodwill or other intangible assets that the Combined Company records in connection with the Plan of Arrangement become impaired, the Combined Company could have to take significant charges against earnings.

        In connection with the accounting for the Plan of Arrangement, the Combined Company expects to record a significant amount of goodwill and other intangible assets. Under U.S. GAAP, the Combined Company must assess, at least annually and potentially more frequently, whether the value of goodwill and other indefinite-lived intangible assets has been impaired. Amortizing intangible assets will be assessed for impairment in the event of an impairment indicator. Any reduction or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could materially adversely affect the Combined Company's results of operations and shareholders' equity in future periods.

Atlantic Power, CPILP and, subsequently, the Combined Company must continue to retain, motivate and recruit executives and other key employees, which may be difficult in light of the uncertainty regarding the Plan of Arrangement, and failure to do so could negatively affect the Combined Company.

        The Combined Company must be successful at retaining, recruiting and motivating key employees following the completion of the Plan of Arrangement. Experienced employees in the power industry are in high demand and competition for their talents can be intense. Employees of both Atlantic Power and CPILP may experience uncertainty about their future role with the Combined Company until, or even after, strategies with regard to the Combined Company are announced or executed. These potential distractions of the Plan of Arrangement may adversely affect the ability of Atlantic Power, CPILP or the Combined Company to attract, motivate and retain executives and other key employees and keep them focused on applicable strategies and goals. A failure by Atlantic Power, CPILP or the Combined Company to retain and motivate executives and other key employees during the period prior to or after the completion of the Plan of Arrangement could have an adverse impact on the business of Atlantic Power, CPILP or the Combined Company.

The Atlantic Power common shares to be received by CPILP unitholders as a result of the Plan of Arrangement will have different rights from the CPILP units.

        Upon completion of the Plan of Arrangement, many CPILP unitholders will become Atlantic Power shareholders and their rights as shareholders will be governed by Atlantic Power's articles and the Business Corporations Act (British Columbia) (the "BCBCA"). The rights associated with CPILP units are different from the rights associated with Atlantic Power common shares. Please see "Comparison of Rights of Atlantic Power Shareholders and CPILP Unitholders" beginning on page 142 for a discussion of the different rights associated with Atlantic Power common shares.

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There are factors that could cause the Plan of Arrangement not to be accretive and could cause dilution to the Combined Company's distributable cash flow per share, which may negatively affect the market price of the Combined Company's common shares.

        Atlantic Power and CPILP currently anticipate that the Plan of Arrangement will be immediately accretive to distributable cash flow per share of the Combined Company. This expectation is based on preliminary estimates, which may materially change. The Combined Company could also encounter additional transaction and integration-related costs or other factors such as the failure to realize all of the benefits anticipated in the Plan of Arrangement. All of these factors could cause dilution to the Combined Company's distributable cash flow per share or decrease or delay the expected accretive effect of the Plan of Arrangement and cause a decrease in the market price of the Combined Company's common shares. Accordingly, Atlantic Power may not be able to increase its dividends following completion of the Plan of Arrangement as currently planned.

Atlantic Power and CPI Preferred Equity Ltd. are subject to Canadian tax.

        As a Canadian corporation, Atlantic Power is generally subject to Canadian federal, provincial and other taxes, and dividends paid by it are generally subject to Canadian withholding tax if paid to a shareholder that is not a resident of Canada. In connection with Atlantic Power's conversion from an IPS structure to a traditional common share structure in 2009 and the related reorganization of its organizational structure, Atlantic Power received a note from its primary US holding company (the "Intercompany Note"). Atlantic Power is required to include in computing its taxable income interest on the Intercompany Note and following the completion of the Plan of Arrangement, income earned by CPILP. Atlantic Power expects that its existing tax attributes initially will be available to offset this income inclusion such that it will not result in an immediate material increase to its liability for Canadian taxes. However, once Atlantic Power fully utilizes its existing tax attributes (or if, for any reason, these attributes were not available), Atlantic Power's Canadian tax liability would materially increase. Although Atlantic Power intends to explore potential opportunities in the future to preserve the tax efficiency of its structure, no assurances can be given that its Canadian tax liability will not materially increase at that time.

        CPI Preferred Equity Ltd., a subsidiary of CPILP, is also a Canadian corporation and is generally subject to Canadian federal, provincial and other taxes. CPI Preferred Equity Ltd. is, and following the completion of the Plan of Arrangement will continue to be, liable to pay material Canadian cash taxes.

Atlantic Power's prior and current structure, and its incorporation of the CPILP structure following the Plan of Arrangement, may be subject to additional US federal income tax liability.

        Under Atlantic Power's prior IPS structure, Atlantic Power treated the subordinated note represented by such IPS's as debt for US federal income tax purposes. Accordingly, Atlantic Power deducted the interest payments on the subordinated notes and reduced its net taxable income treated as "effectively connected income" for US federal income tax purposes. Under Atlantic Power's current structure, its subsidiaries that are incorporated in the United States are subject to US federal income tax on their income at regular corporate rates (currently as high as 35%, plus state and local taxes), and Atlantic Power's primary US holding company will claim interest deductions with respect to the Intercompany Note in computing its income for US federal income tax purposes. To the extent this interest expense is disallowed or is otherwise not deductible, the US federal income tax liability of Atlantic Power's primary US holding company will increase, which could materially affect the after-tax cash available to distribute to Atlantic Power. While Atlantic Power received advice from its US tax counsel, based on certain representations by Atlantic Power and its primary US holding company and determinations made by its independent advisors, as applicable, that the subordinated notes and the Intercompany Note should be treated as debt for US federal income tax purposes, it is possible that the Internal Revenue Service ("IRS") could successfully challenge those positions and assert that

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subordinated notes or the Intercompany Note should be treated as equity rather than debt for US federal income tax purposes. In this case, the otherwise deductible interest on the subordinated notes or the Intercompany Note would be treated as non-deductible distributions and, in the case of the Intercompany Note, would be subject to US withholding tax to the extent Atlantic Power's primary US holding company had current or accumulated earnings and profits. The determination of whether the subordinated notes and the primary US holding company's indebtedness to Atlantic Power is debt or equity for US federal income tax purposes is based on an analysis of the facts and circumstances. There is no clear statutory definition of debt for US federal income tax purposes, and its characterization is governed by principles developed in case law, which analyzes numerous factors that are intended to identify the nature of the purported creditor's interest in the borrower.

        Furthermore, not all courts have applied this analysis in the same manner, and some courts have placed more emphasis on certain factors than other courts have. To the extent it were ultimately determined that the subordinated notes or the Intercompany Note were not debt, Atlantic Power's US federal income tax liability for the applicable open tax years would materially increase, which could materially affect the after-tax cash available to Atlantic Power to distribute. Alternatively, the IRS could argue that the interest on the subordinated notes or the Intercompany Note exceeded or exceeds an arm's length rate, in which case only the portion of the interest expense that does not exceed an arm's length rate may be deductible and, in the case of the Intercompany Note, the remainder would be subject to US withholding tax to the extent Atlantic Power's primary US holding company had current or accumulated earnings and profits. Atlantic Power has received advice from independent advisors that the interest rates on the subordinated notes and the Intercompany Note were, when issued, commercially reasonable under the circumstances, but the advice is not binding on the IRS.

        Furthermore, pursuant to the US "earnings stripping" limitations, Atlantic Power's primary US holding company's deductions attributable to the interest expense on the Intercompany Note may be limited by the amount by which its net interest expense (the interest paid by the US holding company on all debt, including the Intercompany Note, less its interest income) exceeds 50% of its adjusted taxable income (generally, US federal taxable income before net interest expense, net operating loss carryovers, depreciation and amortization). Any disallowed interest expense may currently be carried forward to future years. Moreover, proposed legislation has been introduced, though not enacted, several times in recent years that would further limit the 50% of adjusted taxable income cap described above to 25% of adjusted taxable income, although recent proposals in the Fiscal Year Budget for 2010 would only apply the revised rules to certain foreign corporations that were expatriated. Furthermore, if Atlantic Power's primary US holding company does not make regular interest payments as required under the Intercompany Note, other limitations on the deductibility of interest under US federal income tax laws could apply to defer and/or eliminate all or a portion of the interest deduction that the US holding company would otherwise be entitled to with respect to the Intercompany Note.

        CPILP's US structure has in place intercompany financing arrangements (the "CPILP Financing Arrangements"). While CPILP has received advice from its US accountants, based on certain representations by its holding companies, that the payments on the CPILP Financing Arrangements should be deductible for US federal income tax purposes, it is possible that the IRS could successfully challenge the deductibility of these payments. If the IRS were to succeed in characterizing these payments as non-deductible, the adverse consequences discussed above with respect to the Intercompany Loan could apply in connection with the CPILP Financing Arrangements. In addition, even if the payments are respected as interest, the deduction thereof could nevertheless be limited by the earnings stripping limitations, as discussed in the preceding paragraph. The earnings stripping limitations will also apply to other indebtedness of CPILP's US group that is guaranteed by CPILP or Atlantic Power. Finally, the applicability of recent changes to the US-Canada Income Tax Treaty to the structure associated with certain of the CPILP Financing Arrangements may result in distributions from CPILP's US group to its Canadian parent being subject to a 30% rate of withholding tax instead of the 5% rate that would otherwise have applied.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This joint proxy statement and the documents incorporated by reference herein contain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the financial condition, results of operations, business strategies, operating efficiencies, synergies, revenue enhancements, competitive positions, plans and objectives of management and growth opportunities of Atlantic Power and CPILP, and with respect to the Plan of Arrangement and the markets for CPILP units and Atlantic Power common shares and other matters. Statements in this joint proxy statement and the documents incorporated by reference herein that are not historical facts are hereby identified as forward-looking statements for the purpose of the safe harbor provided by Section 27A of the Securities Act and Section 21E of the Exchange Act and forward-looking information within the meaning defined under applicable Canadian securities legislation (collectively, "forward-looking statements").

        These forward-looking statements relate to, among other things, the expected benefits of the Plan of Arrangement, such as accretion, the ability to pay increased dividends, enhanced cash flow, growth potential, liquidity and access to capital, market profile and financial strength; the position of the Combined Company; and the expected timing of the completion of the transaction.

        Forward-looking statements can generally be identified by the use of words such as "should," "intend," "may," "expect," "believe," "anticipate," "estimate," "continue," "plan," "project," "will," "could," "would," "target," "potential" and other similar expressions. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Although Atlantic Power and CPILP believe that the expectations reflected in such forward-looking statements are reasonable, such statements involve risks and uncertainties, and undue reliance should not be placed on such statements. Certain material factors or assumptions are applied in making forward-looking statements, including, but not limited to, factors and assumptions regarding the items outlined above. Actual results may differ materially from those expressed or implied in such statements. Important factors that could cause actual results to differ materially from these expectations include, among other things:

        Additional information about these factors and about the material factors or assumptions underlying such forward-looking statements may be found in this joint proxy statement, as well as under Item 1A in Atlantic Power's Annual Report on Form 10-K for the fiscal year ended

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December 31, 2010, as updated by subsequent Quarterly Reports on Form 10-Q, all of which are filed with the SEC and have been delivered with, and/or incorporated by reference into, this joint proxy statement. These important factors also include those set forth under the section entitled "Risk Factors", beginning on page 22 of the joint proxy statement.

        Readers are cautioned that any forward-looking statement speaks only as of the date of this joint proxy statement or, if such statement is included in a document incorporated by reference into this joint proxy statement, as of the date of such other document. Neither Atlantic Power nor CPILP undertakes any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as may be required by applicable law. Atlantic Power and CPILP caution further that, as it is not possible to predict or identify all relevant factors that may impact forward-looking statements, the foregoing list should not be considered a complete statement of all potential risks and uncertainties.

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THE ENTITIES

Atlantic Power Corporation

        Atlantic Power owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Atlantic Power's generation projects sell electricity to utilities and other large commercial customers under long-term PPAs, which seek to minimize exposure to changes in commodity prices. Atlantic Power's power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 MW in which Atlantic Power's ownership interest is approximately 871 MW. Atlantic Power's corporate strategy is to generate stable cash flows from Atlantic Power's existing assets and to make accretive acquisitions to sustain Atlantic Power's dividend payout to shareholders, which is currently paid monthly at an annual rate of C$1.094 per share. Atlantic Power's current portfolio consists of interests in 12 operational power generation projects across nine states, one 53 MW biomass project under construction in Georgia, and an 84-mile, 500 kilovolt electric transmission line located in California. Atlantic Power also owns a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development.

        Atlantic Power sells the capacity and power from its projects under PPAs with a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2012 to 2037, Atlantic Power receives payments for electric energy sold to its customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). Atlantic Power also sells steam from a number of its projects under steam sales agreements to industrial purchasers. The transmission system rights owned by Atlantic Power in its power transmission project entitle it to payments indirectly from the utilities that make use of the transmission line.

        Atlantic Power's projects generally operate pursuant to long-term supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and most of the PPAs and steam sales agreements provide for the pass-through or indexing of fuel costs to Atlantic Power's customers.

        Atlantic Power partners with recognized leaders in the independent power business to operate and maintain its projects, including Caithness Energy LLC, Power Plant Management Services and the Western Area Power Administration. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

        Atlantic Power's common shares trade on the NYSE under the symbol "AT" and on the TSX under the symbol "ATP". Additional information about Atlantic Power is included in documents incorporated by reference into this joint proxy statement. See "Where You Can Find More Information" beginning on page 150.

        Atlantic Power is corporation continued under the laws of the Province of British Columbia. Atlantic Power's headquarters are located at 200 Clarendon Street, Floor 25, Boston, Massachusetts, USA 02116, telephone number 617-977-2400. Atlantic Power's registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia, Canada V6C 2G8.

Capital Power Income L.P.

        CPILP's primary business is the ownership and operation of power plants in Canada and the United States, which generate electricity and steam, from which it derives its earnings and cash flows. The power plants generate electricity and steam from a combination of natural gas, waste heat, wood waste, water flow, coal and tire-derived fuel. CPILP's generation projects sell electricity to utilities and other large commercial customers under long-term PPAs, which seek to minimize exposure to changes in commodity prices. At present, CPILP's portfolio consists of 19 wholly-owned power generation assets located in both Canada (in the provinces of British Columbia and Ontario) and the United States (in the states of California, Colorado, Illinois, New Jersey, New York and North Carolina), a 50.15%

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interest in a power generation asset in Washington State, and a 14.3% common equity interest in Primary Energy Recycling Holdings LLC. CPILP's assets have a total net generating capacity of 1,400 MW and more than four million pounds per hour of thermal energy.

        The CPILP units trade on the TSX under the symbol "CPA.UN".

        CPILP is a limited partnership created under the laws of the Province of Ontario pursuant to a limited partnership agreement dated March 27, 1997, as amended, which we refer to in this joint proxy statement as CPILP's partnership agreement. CPILP is only permitted to carry on activities that are directly or indirectly related to the energy supply industry and to hold investments in other entities which are primarily engaged in such industry. The head office of CPILP is located at 10065 Jasper Avenue, Edmonton, Alberta, T5J 3B1. The registered office of CPILP is 200 University Avenue, Toronto, Ontario, M5H 3C6, telephone number 1-866-896-4636 (toll free). See "Information Regarding CPILP" beginning on page 121.

CPI Income Services Ltd.

        The General Partner is the general partner of CPILP and is responsible for the management of CPILP. Pursuant to CPILP's partnership agreement, the General Partner is prohibited from undertaking any business activity other than acting as general partner of CPILP. The General Partner has engaged the Manager, which consists of two subsidiaries of Capital Power, to perform management and administrative services for CPILP and to operate and maintain CPILP's power plants pursuant to certain management and operations agreements. The management and operations agreements will be terminated and/or assigned in connection with the Plan of Arrangement in consideration for the payment of an aggregate of C$10.0 million. See "Summary of the Arrangement Agreement—Summaries of Other Agreements Relating to the Arrangement—Management Agreements Termination Agreement and Management Agreement Assignment Agreement" beginning on page 106.

        The General Partner was incorporated on February 13, 1997 under the CBCA. The General Partner is a wholly-owned subsidiary of CPI Investments. The head and registered office of The General Partner is located at 10065 Jasper Avenue, Edmonton, Alberta, T5J 3B1, telephone number 1-866-896-4636 (toll free).

CPI Investments Inc.

        CPI Investments is a holding company that owns 100% of the shares of the General Partner and, together with the CPILP units held by the General Partner, 29.18% of the outstanding CPILP units.

        Capital Power LP holds a 49% voting interest and a 100% economic interest in CPI Investments and EPCOR holds the other 51% voting interest in CPI Investments. Pursuant to the shareholders agreement in respect of CPI Investments, CPILP and EPCOR agreed that the board of directors of CPI Investments shall consist of three directors and EPCOR is entitled to nominate one person for election to the board of directors of CPI Investments.

        CPI Investments was incorporated on February 12, 2009 under the CBCA. The head and registered office of CPI Investments is located at TD Tower, 5th Floor, 10088-102 Avenue, Edmonton, Alberta, Canada, T5J 2Z1, telephone number 1-866-896-4636 (toll free).

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THE ATLANTIC POWER SPECIAL MEETING

Date, Time and Place

        The special meeting of Atlantic Power shareholders will be held at the King Edward Hotel,                , 37 King Street East, Toronto, Ontario on            , the      day of                , 2011 at the hour of         a.m. (Toronto time).

Purpose of the Special Meeting

        At the Atlantic Power special meeting, Atlantic Power shareholders will be asked to vote on the following resolutions:

Recommendations of the Board of Directors of Atlantic Power

        At a meeting held on June 19, 2011, after considering, Atlantic Power's board of directors unanimously determined that the Arrangement and the other transactions contemplated by the Arrangement Agreement, including the issuance of Atlantic Power common shares necessary to complete the Arrangement, are in the best interests of Atlantic Power and is fair to its stakeholders. Accordingly, the Atlantic Power board of directors unanimously recommends that the Atlantic Power shareholders vote "FOR" the Share Issuance Resolution. For a discussion of the material factors considered by the Atlantic Power board of directors in reaching its conclusions, see "The Arrangement Agreement and Plan of Arrangement—Atlantic Power's Reasons for the Agreement"; Recommendations of the Atlantic Power Board of Directors; beginning on page 55.

        Atlantic Power shareholders should carefully read this joint proxy statement in its entirety for more detailed information concerning the Plan of Arrangement and the Arrangement Agreement. In addition, Atlantic Power shareholders are directed to the Arrangement Agreement which is included as Annex A in this joint proxy statement.

Share Issuance Resolution

        Pursuant to the rules of the NYSE and TSX, securityholder approval is required in instances where the number of securities issued or issuable in payment of the purchase price in a transaction such as the Plan of Arrangement exceeds 20% (NYSE) or 25% (TSX) of the number of securities of the listed issuer which are outstanding, on a non-diluted basis. Because the Arrangement Agreement contemplates the issuance of Atlantic Power common shares in excess of these thresholds on a non-diluted basis, the rules of the NYSE and TSX require that Atlantic Power must obtain approval of the Share Issuance Resolution by the holders of a majority of the Atlantic Power common shares represented in person or by proxy at the Atlantic Power special meeting.

        As of the close of business on the date of this joint proxy statement, there were approximately 68.6 million outstanding Atlantic Power common shares. Pursuant to the Plan of Arrangement, Atlantic

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Power will issue approximately 31.5 million Atlantic Power common shares (equal to approximately 46% of Atlantic Power's current issued and outstanding common shares).

Record Date; Shares Entitled to Vote

        Only holders of Atlantic Power common shares at the close of business on                , 2011, the record date for the Atlantic Power special meeting, will be entitled to notice of, and to vote at, the Atlantic Power special meeting or any adjournments or postponements thereof, except to the extent the shareholder has transferred any such common shares after the record date and the transferee of such common shares establishes ownership thereof and makes a written demand to the Corporate Secretary of Atlantic Power, not later than 10 days before the date of the special meeting, to be included in the list of shareholders entitled to vote at the special meeting, in which case the transferee will be entitled to vote such common shares. On the record date, there were outstanding a total of approximately million Atlantic Power common shares. Each outstanding Atlantic Power common share is entitled to one vote on the Share Issuance Resolution and any other matter properly coming before the Atlantic Power special meeting. The Atlantic Power common shares represented by the proxy will be voted for, voted against or withheld from voting in accordance with the instructions of the shareholder on any ballot that may be called for. If the shareholder specifies that the shares registered in the shareholder's name be voted for, voted against or withheld with respect to any matter to be acted upon, the shares will be voted accordingly.

Share Ownership by and Voting Rights of Directors and Executive Officers

        As of the close of business on the Atlantic Power record date, Atlantic Power's directors and executive officers and their affiliates beneficially owned and had the right to vote 0.36 million Atlantic Power common shares at the Atlantic Power special meeting, which represents approximately 0.01% of the Atlantic Power common shares entitled to vote at the Atlantic Power special meeting. Each of the directors and officers of Atlantic Power have indicated their intention to vote in favor of the Share Issuance Resolution.

Quorum

        A quorum must be present at the Atlantic Power special meeting for any business to be conducted. Pursuant to Atlantic Power's articles, the presence of two persons, present in person, each being an Atlantic Power shareholder entitled to vote or a duly appointed proxy for an Atlantic Power shareholder so entitled constitutes a quorum.

Required Vote

        The Share Issuance Resolution will be approved if a majority of the votes cast by Atlantic Power shareholders, either in person or by proxy at the Atlantic Power special meeting, vote in favor of the resolution.

Failure to Vote and Broker Non-Votes

        If you are an Atlantic Power shareholder and fail to vote or fail to instruct your broker, investment dealer or other intermediary to vote, it will have no effect on any of the Atlantic Power proposals, assuming a quorum is present.

Appointment of Proxyholder

        The persons designated by management of Atlantic Power in the enclosed proxy card are Irving Gerstein and John McNeil. Each Atlantic Power shareholder has the right to appoint as proxyholder a person or company, who need not be a shareholder of Atlantic Power, other than the persons

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designated by management of Atlantic Power in the enclosed form of proxy, to attend and act on the shareholder's behalf at the Atlantic Power special meeting or at any adjournment or postponement thereof. Such right may be exercised by inserting the name of the person or company in the blank space provided in the enclosed proxy card or by completing another proxy card.

        A document appointing a proxy must be in writing and completed and signed by a shareholder or his or her attorney authorized in writing or, if the shareholder is a corporation, under its corporate seal or by an officer or attorney thereof duly authorized. Instructions provided to the agent by a shareholder must be in writing and completed and signed by the shareholder or his or her attorney authorized in writing or, if the shareholder is a corporation, under its corporate seal or by an officer or attorney thereof duly authorized. Persons signing as officers, attorneys, executors, administrators, and trustees or similarly otherwise should so indicate and provide satisfactory evidence of such authority.

Record Holders

        If you are a registered holder of Atlantic Power common shares as of the close of business on the record date for the Atlantic Power special meeting, a form of proxy is enclosed for your use. Atlantic Power requests that you vote your shares by telephone or through the Internet, or sign the accompanying form of proxy and return it promptly in the enclosed postage-paid envelope. Information and applicable deadlines for voting by telephone or through the Internet are set forth on the enclosed form of proxy. When the enclosed form of proxy is returned completed and properly executed, the Atlantic Power common shares represented by it will be voted at the Atlantic Power special meeting or any adjournment or postponement thereof in accordance with the instructions contained in the form of proxy and if the shareholder specifies a choice with respect to any matter to be acted upon, the Atlantic Power common shares will be voted accordingly. Your telephone or Internet vote authorizes the named proxies to vote your shares in the same manner as if you had completed, signed and returned a form of proxy.

        Your vote is important. Accordingly, if you are a registered holder of Atlantic Power common shares as of the close of business on the record date, please sign and return the enclosed form of proxy or vote via telephone or the Internet whether or not you plan to attend the Atlantic Power special meeting in person.

        If a proxy is signed and returned without an indication as to how the Atlantic Power common shares represented are to be voted with regard to a particular proposal, the Atlantic Power common shares represented by the proxy will be voted in favor of the Share Issuance Resolution. At the date hereof, the Atlantic Power board of directors has no knowledge of any business that will be presented for consideration at the special meeting and which would be required to be set forth in this joint proxy statement or the related Atlantic Power proxy other than the matters set forth in Atlantic Power's Notice of Special Meeting of Shareholders. Business transacted at the Atlantic Power special meeting is expected to be limited to those matters set forth in such notice. Nonetheless, if any amendments to matters identified in the accompanying Notice of Atlantic Power Special Meeting of Shareholders or any other matter is properly presented at the Atlantic Power special meeting for consideration, it is intended that the persons named in the enclosed proxy and acting thereunder will vote in accordance with their best judgment and pursuant to such discretionary authority on such matter.

Shares Held in Street Name/Non-Registered Shareholders

        The proxy card provided with this joint proxy statement will indicate whether or not you are a registered shareholder. Non-registered shareholders hold their Atlantic Power common shares through intermediaries, such as banks, trust companies, securities dealers or brokers. If you are a non-registered shareholder, the intermediary holding your Atlantic Power common shares should provide a voting instruction form which you must complete by using any one of the methods outlined therein. This

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voting instruction form will constitute voting instructions that the intermediary must follow and should be returned in accordance with the instructions to ensure it is counted for the Atlantic Power special meeting. In order to expedite your vote, you may vote by using a touch-tone telephone or via the Internet, following the instructions outlined on the voting instruction form.

        If, as a non-registered shareholder, you wish to attend the Atlantic Power special meeting and vote your common shares in person, or have another person attend and vote your common shares on your behalf, you should fill your own name, or the name of your appointee, in the space provided on the voting instruction form. An intermediary's voting instruction form will likely provide corresponding instructions to cast your vote in person. In either case, you should carefully follow the instructions provided by the intermediary and contact the intermediary promptly if you need help.

        A non-registered shareholder may revoke a proxy or voting instruction which has been previously given to an intermediary by written notice to the intermediary. In order to ensure that the intermediary acts upon a revocation, the written notice should be received by the intermediary well in advance of the Atlantic Power special meeting.

Revocability of Proxy; Changing Your Vote

        If you are a registered holder of Atlantic Power common shares as of the close of business on the record date for the Atlantic Power special meeting: You can change your vote at any time before the start of the Atlantic Power special meeting, unless otherwise noted. In addition to revocation in any other manner permitted by law, you can do this in one of the following ways:

        If you choose any of the foregoing methods, your notice of revocation or your new proxy must be received by Atlantic Power no later than the beginning of the Atlantic Power special meeting. If you have voted your shares by telephone or through the Internet, you may revoke your prior telephone or Internet vote by any manner described above.

        If you hold Atlantic Power common shares in "street name":    You must contact your broker, investment dealer or other intermediary in writing to change your vote. In order to ensure that the broker, investment dealer or other intermediary acts upon revocation, the written notice should be received by the broker, investment dealer or other intermediary well in advance of your special meeting.

Additional Disclosure Required by Canadian Securities Laws

        Management of Atlantic Power is soliciting proxies for use at the Atlantic Power special meeting or at any adjournment or postponement thereof. In accordance with the Arrangement Agreement, the cost of proxy solicitation for the Atlantic Power special meeting will be borne by Atlantic Power. In addition to the use of the mail, proxies may be solicited by directors, officers and other employees of Atlantic Power, without additional remuneration, by personal interview, telephone, facsimile or

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otherwise. Atlantic Power will also request brokerage firms, nominees, custodians and fiduciaries to forward proxy materials to the beneficial owners of shares and will provide customary reimbursement to such firms for the cost of forwarding these materials. Atlantic Power has retained            to assist in its solicitation of proxies and has agreed to pay them a fee of approximately             , plus reasonable expenses, for these services.

        To the knowledge of the directors of Atlantic Power, there are no persons that beneficially own or exercise control or direction over Atlantic Power common shares carrying 10% or more of the votes attached to the issued and outstanding Atlantic Power common shares. See "Information Regarding Atlantic Power—Security Ownership of Certain Beneficial Owners and Management" beginning on page 119.

        Disclosure regarding compensation of the directors of Atlantic Power, compensation of the named executive officers of Atlantic Power, the equity compensation plans of Atlantic Power and Atlantic Power's compensation discussion and analysis may be found at pages C-13 to C-30 of Atlantic Power's management information circular filed on SEDAR on May 2, 2011 under the headings "Compensation Discussion and Analysis," "Summary Compensation Table," "Outstanding Share-Based Awards," "Stock Vested," "Equity Compensation Plan Information," "Employment Contracts," "Termination and Change of Control Benefits," "Compensation Risk Assessment" and "Compensation of Directors," which sections are incorporated by reference herein.

        Atlantic Power has obtained a directors' and officers' policy of insurance for directors and officers of the Atlantic Power and its subsidiaries that provides an aggregate limit of liability to the insured directors, officers and corporations of C$40.0 million.

        The articles of Atlantic Power also provide for the indemnification of the directors and officers from and against liability and costs in respect of any action or suit against them in connection with the execution of their duties of office, subject to certain limitations.

        To the knowledge of the directors of Atlantic Power, other than as disclosed under the heading "The Atlantic Power Special Meeting—Directors' and Officers' Insurance and Indemnification," no insider, director or any associate or affiliate of any such persons, had any material interest, direct or indirect, by way of beneficial ownership of securities or otherwise, in any material transaction with Atlantic Power since the commencement of Atlantic Power's last financial period.

        The board of directors will review and approve all relationships and transactions in which Atlantic Power and any of the its directors and executive officers and their immediate family members, as well as holders of more than 5% of any class of its voting securities and their family members, have a direct or indirect material interest. In approving or rejecting such proposed relationships and transactions, the board shall consider the relevant facts and circumstances available and deemed relevant to this determination. Atlantic Power's Nominating and Governance Committee is responsible under its charter for monitoring compliance with the Code of Business Conduct and Ethics.

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THE CPILP SPECIAL MEETING

Date, Time and Place

        The special meeting of CPILP unitholders will be held at the            ,             on            , the             day of                        , 2011 at the hour of         a.m. (Edmonton time).

Purpose of the Special Meeting

        At the CPILP special meeting, CPILP unitholders will be asked:

Recommendations of the Board of Directors of the General Partner

        At a meeting held on June 19, 2011, after considering, among other things, the oral opinions of CIBC and Greenhill, subsequently confirmed in writing, the full text of which are attached as Annexes D and E, respectively, of this joint proxy statement, the members of the board of directors of the General Partner entitled to vote, being the independent directors of the General Partner, determined unanimously that the Arrangement is in the best interests of CPILP and is fair to the CPILP unitholders and resolved unanimously to recommend to the CPILP unitholders that they vote in favor of the Arrangement. The members of the board of directors of the General Partner entitled to vote also unanimously approved the Arrangement and the execution and performance of the Arrangement Agreement. Accordingly, the board of directors of the General Partner unanimously recommends that the CPILP unitholders vote "FOR" the approval of the Arrangement Resolution. For a discussion of the material factors considered by the board of directors of the General Partner in reaching its conclusions, see "The Arrangement Agreement and Plan of Arrangement—; CPILP's Reasons for the Plan of Arrangement"; Recommendations of the Board of Directors of the General Partner beginning on page 77.

        CPILP unitholders should carefully read this joint proxy statement in its entirety for more detailed information concerning the Plan of Arrangement and the Arrangement Agreement. In addition, CPILP unitholders are directed to the Arrangement Agreement which is included as Annex A in this joint proxy statement.

Record Date; Units Entitled to Vote

        Only holders of CPILP units at the close of business on                        , 2011, the record date for the CPILP special meeting, will be entitled to notice of, and to vote at, the CPILP special meeting or any adjournments or postponements thereof. On the record date, there were outstanding a total of 56,597,899 CPILP units. Each outstanding CPILP unit is entitled to one vote on each proposal and any other matter properly coming before the CPILP special meeting.

Unit Ownership by and Voting Rights of Directors and Executive Officers

        As of the close of business on the CPILP record date, CPILP's directors and executive officers and their affiliates beneficially owned and had the right to vote            CPILP units at the CPILP special meeting, which represents approximately        % of the CPILP units entitled to vote at the CPILP

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special meeting. It is expected that CPILP's directors and executive officers will vote in favor of all resolutions.

Quorum

        A quorum must be present at the CPILP special meeting for any business to be conducted. Pursuant to the limited partnership agreement of CPILP, the quorum for the CPILP special meeting is one or more CPILP unitholders present in person or by proxy representing at least 10% of the outstanding units.

Required Vote

        Pursuant to the Interim Order, the number of votes required to pass the Arrangement Resolution shall be not less than 662/3% of the votes cast by CPILP unitholders, either in person or by proxy, at the CPILP special meeting. In addition, the Arrangement Resolution must be approved by a simple majority of the votes cast by the CPILP unitholders present in person or by proxy at the CPILP special meeting, after excluding those votes required to be excluded pursuant to the minority approval provisions of MI 61-101, being the votes of "interested parties" and their related parties and joint actors, which include the General Partner and CPI Investments. Notwithstanding the foregoing, the Arrangement Resolution authorizes the board of directors of the General Partner, without further notice to or approval of the CPILP unitholders, subject to the terms of the Plan of Arrangement and the Arrangement Agreement, to amend the Plan of Arrangement or the Arrangement Agreement or to decide not to proceed with the Plan of Arrangement at any time prior to the Plan of Arrangement becoming effective pursuant to the provisions of the CBCA. See "The Arrangement Agreement and Plan of Arrangement—Canadian Securities Laws Matters" beginning on page 85.

Failure to Vote and Broker Non-Votes

        If you are a CPILP unitholder and fail to vote or fail to instruct your broker, investment dealer or other intermediary to vote, it will have no effect on any of the CPILP proposals, assuming a quorum is present.

Appointment of Proxyholder

        The persons designated by management of the General Partner in the enclosed proxy card are Stuart A. Lee, a director and president of the General Partner, and Anthony Scozzafava, the chief financial officer of the General Partner. Each CPILP unitholder has the right to appoint as proxyholder a person or company, who need not be a unitholder of CPILP, other than the persons designated by management of the General Partner in the enclosed form of proxy, to attend and act on the unitholder's behalf at the CPILP special meeting or at any adjournment or postponement thereof. Such right may be exercised by inserting the name of the person or company in the blank space provided in the enclosed proxy card or by completing another proxy card.

Record Holders

        CDS Clearing and Depositary Services Inc. is the only registered holder of CPILP units. All other holders of CPILP units are non-registered holders. See "—Units Held in Street Name/Non-Registered CPILP Unitholders" beginning on page 41. If you are a registered holder of CPILP units as of the close of business on the record date for the CPILP special meeting, a proxy card is enclosed for your use. CPILP requests that you vote your shares by telephone or through the Internet, or sign the accompanying proxy card and return it promptly in the enclosed postage-paid envelope. Information and applicable deadlines for voting by telephone or through the Internet are set forth on the enclosed proxy card. When the enclosed proxy card is returned properly executed, the CPILP units represented by it will be voted at the CPILP special meeting or any adjournment or postponement thereof in

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accordance with the instructions contained in the proxy card and if the unitholder specifies a choice with respect to any matter to be acted upon, the CPILP units will be voted accordingly. Your telephone or Internet vote authorizes the named proxies to vote your units in the same manner as if you had marked, signed and returned a proxy card.

        Your vote is important. Accordingly, if you are a registered holder of CPILP units as of the close of business on the record date, please sign and return the enclosed proxy card or vote via telephone or the Internet whether or not you plan to attend the CPILP special meeting in person.

        If a proxy card is signed and returned without an indication as to how the CPILP units represented are to be voted with regard to a particular proposal, the CPILP units represented by the proxy will be voted in accordance with the recommendations of the General Partner's board of directors. At the date hereof, the board of directors of the General Partner has no knowledge of any business that will be presented for consideration at the special meeting and which would be required to be set forth in this joint proxy statement or the related CPILP proxy card other than the matters set forth in CPILP's Notice of Special Meeting of Unitholders. Business transacted at the CPILP special meeting is expected to be limited to those matters set forth in such notice. Nonetheless, if any amendments to matters identified in the accompanying Notice of CPILP Special Meeting of Unitholders or any other matter is properly presented at the CPILP special meeting for consideration, it is intended that the persons named in the enclosed proxy card and acting thereunder will vote in accordance with their best judgment and pursuant to such discretionary authority on such matter.

Units Held in Street Name/Non-Registered CPILP Unitholders

        The proxy card provided with this joint proxy statement will indicate whether or not you are a registered unitholder. All holders other than CDS Clearing and Depositary Services Inc. are non-registered holders. Non-registered unitholders hold their CPILP units through intermediaries, such as banks, trust companies, securities dealers or brokers. If you are a non-registered unitholder, the intermediary holding your CPILP units should provide a voting instruction form which you must complete by using any one of the methods outlined therein. This voting instruction form will constitute voting instructions that the intermediary must follow and should be returned in accordance with the instructions to ensure it is counted for the CPILP special meeting. In order to expedite your vote, you may vote by using a touch-tone telephone or via the Internet, following the instructions outlined on the voting instruction form.

        If, as a non-registered unitholder, you wish to attend the CPILP special meeting and vote your units in person, or have another person attend and vote your units on your behalf, you should fill your own name, or the name of your appointee, in the space provided on the voting instruction form. An intermediary's voting instruction form will likely provide corresponding instructions to cast your vote in person. In either case, you should carefully follow the instructions provided by the intermediary and contact the intermediary promptly if you need help.

        A non-registered unitholder may revoke a proxy or voting instruction which has been previously given to an intermediary by written notice to the intermediary. In order to ensure that the intermediary acts upon a revocation, the written notice should be received by the intermediary well in advance of the CPILP special meeting.

Revocability of Proxy; Changing Your Vote

        If you are a registered holder of CPILP units as of the close of business on the record date for the CPILP special meeting: You can change your vote at any time before the start of your special meeting, unless otherwise noted. In addition to revocation in any other manner permitted by law, you can do this in one of the following ways:

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        If you choose any of the foregoing methods, your notice of revocation or your new proxy must be received by CPILP no later than the beginning of the CPILP special meeting. If you have voted your units by telephone or through the Internet, you may revoke your prior telephone or Internet vote by any manner described above.

        If you hold CPILP units in "street name":    You must contact your broker, investment dealer or other intermediary in writing to change your vote. In order to ensure that the broker, investment dealer or other intermediary acts upon revocation, the written notice should be received by the broker, investment dealer or other intermediary well in advance of your special meeting.

Solicitation of Proxies

        The management of the General Partner is soliciting proxies for use at the CPILP special meeting or at any adjournment or postponement thereof. In accordance with the Arrangement Agreement, the cost of proxy solicitation for the CPILP special meeting will be borne by CPILP. In addition to the use of the mail, proxies may be solicited by directors, officers and other employees of CPILP, without additional remuneration, by personal interview, telephone, facsimile or otherwise. CPILP will also request brokerage firms, nominees, custodians and fiduciaries to forward proxy materials to the beneficial owners of units and will provide customary reimbursement to such firms for the cost of forwarding these materials. CPILP has retained Georgeson Shareholder Communications Canada, Inc. to assist in its solicitation of proxies and has agreed to pay them a fee of approximately C$40,000, plus reasonable expenses, for these services.

Principal Unitholders

        CPI Investments, together with its wholly-owned subsidiary CPI Incomes Services Ltd., holds 16,513,504 units representing approximately 29.18% of the issued and outstanding CPILP units. To the knowledge of the directors of the General Partner, there are no other persons that beneficially own or exercise control or direction over CPILP units carrying 10% or more of the votes attached to the issued and outstanding CPILP units.

Procedures for the Surrender of Unit Certificate and Receipt of Consideration

Letter of Transmittal and Election Form

General

        Each registered holder of CPILP units is required to validly complete and duly sign a Letter of Transmittal and Election Form and submit such document, together with such holder's CPILP unit certificate(s), if any, to the Depositary in order to receive the consideration under the Plan of Arrangement.

        The details of the procedures for the deposit of CPILP unit certificates and the delivery by the Depositary of Atlantic Power common shares and cash are set out in the Letter of Transmittal and Election Form accompanying this joint proxy statement.

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        Registered holders of CPILP units who have not received a Letter of Transmittal and Election Form should contact CPILP, Attention:            , at            or Computershare Investor Services Inc. at             .

        Only registered holders of CPILP units are required to submit a Letter of Transmittal and Election Form. CDS Clearing and Depositary Services Inc. is the only registered holder of CPILP units. All other holders of CPILP units are non-registered holders. If you are a non-registered holder, you should carefully follow any instructions provided to you by your broker, dealer or investment advisor for making an election. See "—Units Registered in the Name of an Intermediary" beginning on page 46. Failure to return the Letter of Transmittal and Election Form and the certificates representing your CPILP units, if any, will result in a delay in you receiving your cash or Atlantic Power common shares under the Plan of Arrangement.

        Each registered holder of CPILP units must validly complete, duly sign and return the enclosed Letter of Transmittal and Election Form, together with the certificate(s) representing their CPILP units, if any, to the Depositary at one of the offices specified in the Letter of Transmittal and Election Form.

        CPILP unitholders who deposit a validly completed and duly signed Letter of Transmittal and Election Form, together with accompanying CPILP unit certificate(s), if any, will be entitled to receive in exchange therefor, and the Depositary will deliver as soon as possible to such CPILP unitholder following the Effective Time (i) a cheque for the cash consideration to which such CPILP unitholder is entitled to receive in accordance with the Plan of Arrangement, and (ii) a certificate representing that number of Atlantic Power common shares which such CPILP unitholder has the right to receive under the Plan of Arrangement (together with any dividends or distributions with respect thereto pursuant to the Plan of Arrangement), less any amounts required to be withheld. It is recommended that CPILP unitholders complete and return their Letter of Transmittal and Election Form to the Depositary on or before the Election Deadline (as defined below). Once CPILP unitholders surrender their CPILP unit certificates, they will not be entitled to sell the securities to which those certificates relate.

        If a CPILP unitholder deposits CPILP units with the Depositary prior to the CPILP special meeting and if the Arrangement is approved at the CPILP special meeting (including any adjournment or postponement thereof) then the deposit of the CPILP units is irrevocable unless the Plan of Arrangement is not subsequently completed.

        CPILP unitholders who do not forward to the Depositary a validly completed and duly signed Letter of Transmittal and Election Form, together with their CPILP unit certificate(s), if any, will not receive the cash and/or Atlantic Power common shares, as applicable, to which they are otherwise entitled until such a deposit is made. Whether or not CPILP unitholders forward their CPILP unit certificate(s) upon the completion of the Plan of Arrangement on the Effective Date, CPILP unitholders will cease to be unitholders of CPILP as of the Effective Date and will only be entitled to receive the cash and/or Atlantic Power common shares to which they are entitled under the Plan of Arrangement.

        No commission will be charged to CPILP unitholders who deliver their certificate(s) evidencing CPILP units according to the instructions set out in the Letter of Transmittal and Election Form. It is not possible to determine precisely when the Plan of Arrangement will become effective. If the Final Order is obtained and all conditions set forth in the Arrangement Agreement are satisfied or waived, CPILP or the General Partner will file the Articles of Arrangement giving effect to the Plan of Arrangement as soon as reasonably practicable, such that the Effective Date is expected to be on or about                        , 2011.

How to Make an Election

        Pursuant to the terms of the Arrangement Agreement and the Plan of Arrangement, CPILP unitholders are entitled to receive, at their election, for each CPILP unit held (i) C$19.40 in cash or

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(ii) 1.3 Atlantic Power common shares, subject to the Aggregate Cash Maximum (as defined below) and the Aggregate Share Maximum (as defined below), by completing a Letter of Transmittal and Election Form and sending it to the Depositary, together with any certificates representing the CPILP units in accordance with the instructions provided on the form, at one of the offices specified in the Letter of Transmittal and Election Form.

        The Election Deadline to deposit such properly completed Letter of Transmittal and Election Form with the Depositary is 5:00 p.m. (Edmonton time) on the date that is three business days prior to the date of the CPILP special meeting. Assuming the CPILP special meeting is held on                        , 2011, the Election Deadline will be 5:00 p.m. (Edmonton time) on                         , 2011. Each CPILP unitholder's election is subject to the proration provisions described below.

What Happens if a CPILP unitholder Fails to Make a Valid Election

        Any CPILP unitholder who does not deposit a duly completed Letter of Transmittal and Election Form with the Depositary prior to the Election Deadline, or otherwise fails to comply with the requirements of the Plan of Arrangement and the Letter of Transmittal and Election Form with respect to such holder's election to receive Cash Consideration or Share Consideration, shall be deemed to have elected to receive the Share Consideration in respect of all of such holder's CPILP units.

Proration Provisions

        With respect to the Cash Consideration, the Plan of Arrangement provides that the aggregate amount of cash available to be paid under the Plan of Arrangement is limited to C$506,513,834 (the "Aggregate Cash Maximum"). If the aggregate amount of Cash Consideration that would be paid to CPILP unitholders pursuant to the Plan of Arrangement (the "Aggregate Cash Elected"), but for prorationing pursuant to the Plan of Arrangement, exceeds the Aggregate Cash Maximum, then, notwithstanding any election to receive the Cash Consideration, the aggregate amount of cash paid to each CPILP unitholder that made an election to receive the Cash Consideration and to Capital Power LP (if it makes an election to receive Cash Consideration) will be prorated (based on the fraction equal to the Aggregate Cash Maximum divided by the Aggregate Cash Elected) so that the aggregate amount of cash payable to all such CPILP unitholders and Capital Power LP shall be equal to the Aggregate Cash Maximum (the amount of the reduction in cash payable to any CPILP unitholder being the "Cash Reduction" in respect of such holder). In lieu of the amount of cash equal to the Cash Reduction in respect of a CPILP unitholder, each such CPILP unitholder shall receive a number of Atlantic Power common shares equal to the product of (i) the Cash Reduction divided by the Cash Consideration per CPILP unit and (ii) 1.3.

        With respect to the Share Consideration, the Plan of Arrangement provides that the aggregate number of Atlantic Power common shares to be issued under the Plan of Arrangement is limited to 31,500,221 shares (the "Aggregate Share Maximum"). If the aggregate number of Atlantic Power common shares that would be issued to CPILP unitholders pursuant to the Plan of Arrangement (the "Aggregate Shares Elected"), but for prorationing pursuant to the Plan of Arrangement, exceeds the Aggregate Share Maximum, then, notwithstanding any election or deemed election to receive the Share Consideration, the aggregate number of Atlantic Power common shares issued to each CPILP unitholder that made or was deemed to make an election to receive the Share Consideration and to Capital Power LP (if it makes or is deemed to make an election to receive Share Consideration) will be prorated (based on the fraction equal to the Aggregate Share Maximum divided by the Aggregate Shares Elected) so that the aggregate number of Atlantic Power common shares issuable to all such CPILP unitholders and Capital Power LP shall be equal to the Aggregate Share Maximum (the reduction in the number of Atlantic Power common shares payable to any CPILP unitholder being the "Share Reduction" in respect of such holder). In lieu of the number of the Atlantic Power common shares equal to the Share Reduction in respect of a CPILP unitholder, each such CPILP unitholder

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shall receive an amount of cash equal to the product of (i) the Share Reduction divided by 1.3 and (ii) the Cash Consideration per CPILP unit.

Fractional Shares

        In no event shall any holder of CPILP units be entitled to receive a fraction of an Atlantic Power common share in consideration therefore. Where the aggregate number of Atlantic Power common shares to be issued to a holder of CPILP units as consideration under the Plan of Arrangement would result in a fraction of an Atlantic Power common share being issuable, the number of Atlantic Power common shares to be received by such holder shall be rounded down to the nearest whole number of Atlantic Power common shares and no CPILP unitholder will be entitled to any compensation in respect of such fractional Atlantic Power common share.

Fractional Cash

        Any cash payable to a CPILP unitholder pursuant to the Plan of Arrangement shall be rounded down to the nearest whole cent.

Method of Delivery

        The method of delivery of certificates representing CPILP units and all other required documents is at the option and risk of the person depositing his or her CPILP units. Any use of the mail to forward certificates representing CPILP units or the related Letter of Transmittal and Election Form is at the election and sole risk of the person depositing CPILP units, and documents so mailed shall be deemed to have been received by CPILP only upon actual receipt by the Depositary. If such certificates and other documents are to be mailed, CPILP recommends that insured mail be used with return receipt or acknowledgement of receipt requested.

        Cheque(s) representing the cash payable and/or certificate(s) representing the Atlantic Power common shares issuable to a former holder of CPILP units who has complied with the procedures set out above will, as soon as practicable after the Effective Date and after the receipt of all required documents: (i) be forwarded to the former CPILP unitholder at the address specified in the Letter of Transmittal and Election Form by first-class mail; or (ii) be made available at the offices of the Depositary, Computershare Investor Services Inc.,                     for pickup by the holder as requested by the holder, in the Letter of Transmittal and Election Form. Under no circumstances will interest accrue or be paid by CPILP, Atlantic Power or the Depositary on the consideration for the CPILP units to persons depositing CPILP units with the Depositary, regardless of any delay in issuing the applicable cheques and/or Atlantic Power common shares, as applicable, for the CPILP units.

Destroyed, Lost or Misplaced Unit Certificates

        In the event any certificate which immediately prior to the Effective Time represented one or more outstanding CPILP units has been lost, stolen or destroyed, upon the making of an affidavit of that fact by the holder claiming such certificate to be lost, stolen or destroyed, the Depositary will deliver, in exchange for such lost, stolen or destroyed certificate, certificates representing Atlantic Power common shares and/or a cheque for the amount of any cash consideration to which such CPILP unitholder is entitled to receive in accordance with such holder's Letter of Transmittal and Election Form and the Plan of Arrangement, in each case, less any amounts required to be withheld. When authorizing such payment and delivery in exchange for any lost, stolen or destroyed certificate, the Person to whom cheques and/or certificates are to be issued shall, as a condition precedent to the payment and delivery thereof, give a bond satisfactory to Atlantic Power and the Depositary in such sum as Atlantic Power and the Depositary may direct, or otherwise indemnify CPILP, Atlantic Power and the Depositary in a manner satisfactory to Atlantic Power and the Depositary, against any claim that may be made with respect to the certificate alleged to have been lost, stolen or destroyed.

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Units Registered in the Name of Intermediary

        Only registered holders of CPILP units are entitled to make an election as to the type of consideration they will receive under the Plan of Arrangement. CDS Clearing and Depositary Services Inc. ("CDS") is the only registered holder of CPILP units. CDS will establish an electronic facility which will allow intermediaries to communicate election instructions they receive from brokers and the holders of CPILP units they represent to CDS who will, in turn, make the election on their behalf as the registered holder of CPILP units. CPILP unitholders who are beneficial holders of CPILP units should contact their investment advisor to determine how their election can be made. CPILP unitholders may also contact            in the manner set out on the back page of this management proxy circular and joint proxy statement for further information and assistance. If you fail to instruct your broker or investment advisor with respect to your election then, unless your broker or investment advisor has discretionary authority, they will not make an election on your behalf and you will be deemed to have elected Share Consideration in respect of your CPILP units.

Failure to Deliver Unit Certificates

        Any certificate which immediately prior to the Effective Time represented outstanding CPILP units that is not deposited with the Depositary together with all other instruments or documents required by the Plan of Arrangement on or prior to the sixth anniversary of the Effective Date will cease to represent a claim or interest of any kind or nature as a CPILP unitholder or as a shareholder of Atlantic Power. On such date, the cash and Atlantic Power common shares to which the former holder of the certificate referred to in the preceding sentence was ultimately entitled under the Plan of Arrangement will be deemed to have been donated, surrendered and forfeited for no consideration to Atlantic Power. None of Atlantic Power, CPILP, the General Partner, CPI Investments or the Depositary shall be liable to any Person in respect of any cash or Atlantic Power common shares (or dividends, distributions and interest in respect thereof) delivered to a public official pursuant to any applicable abandoned property, escheat or similar law.

Withholding

        A holder of CPILP units will be liable for, and Atlantic Power and the Depositary will be entitled to deduct and withhold from any amount paid to such holder, such amounts as each of Atlantic Power or the Depositary is required or permitted to deduct and withhold under the Tax Act, the United States Internal Revenue Code of 1986, as amended, or any provision of applicable federal, provincial, state, local or foreign tax law with respect to any consideration otherwise payable under the Plan of Arrangement to such holder, and Atlantic Power and the Depositary will be entitled to recover from such holder any portion of such amounts that is required to be withheld thereunder and is not otherwise deducted or withheld. To the extent that amounts are so withheld, such withheld amounts shall be treated for all purposes hereof as having been paid to the holder of the CPILP units in respect of which such deduction and withholding was made, provided that such withheld amounts are actually remitted by Atlantic Power or the Depositary to the appropriate taxing authority in the name of the relevant holder of CPILP units. To the extent that the amount so required or entitled to be deducted or withheld from any payment to such a holder exceeds the cash portion of the consideration otherwise payable to the holder, Atlantic Power and the Depositary are authorized pursuant to the Plan of Arrangement to sell or otherwise dispose of such portion of the Atlantic Power common shares otherwise deliverable to such holder as is necessary to provide sufficient funds to Atlantic Power or the Depositary, as the case may be, to enable it to comply with such deduction or withholding requirement or entitlement and Atlantic Power or the Depositary will notify the holder thereof and remit to such holder any unapplied balance of the net proceeds of such sale.

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APPRAISAL/DISSENT RIGHTS

        Appraisal or dissent rights are statutory rights that, if applicable under law, enable shareholders or unitholders, as applicable, to dissent from an extraordinary transaction, such as the Plan of Arrangement, and to demand that the corporation or other entity pay the fair value for their shares or units, as applicable, as determined by a court in a judicial proceeding instead of receiving the consideration offered to holders in connection with the extraordinary transaction. Appraisal or dissent rights are not available in all circumstances.


Atlantic Power

        The holders of Atlantic Power common shares are not entitled to dissent rights in connection with the Share Issuance Resolution.


CPILP

        The unitholders of CPILP are not entitled to dissent rights in connection with the Arrangement Resolution.

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THE ARRANGEMENT AGREEMENT AND PLAN OF ARRANGEMENT

Effects of the Plan of Arrangement

        In order to effect the combination of Atlantic Power and CPILP, Atlantic Power will acquire, directly and indirectly, all of the outstanding CPILP units for C$19.40 per unit in cash or 1.3 Atlantic Power common shares per unit, all subject to proration.

        Under the terms of the Plan of Arrangement, CPILP unitholders will be entitled to elect to receive either C$19.40 in cash or 1.3 Atlantic Power common shares for each CPILP unit held. All cash elections will be subject to proration if total cash elections exceed approximately C$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares. As part of the Plan of Arrangement, Atlantic Power will acquire all of the outstanding shares of CPI Investments, the direct and indirect holder of 16,513,504 CPILP units, on effectively the same basis as the acquisition of CPILP units under the Plan of Arrangement. Atlantic Power shareholders will continue to hold their existing Atlantic Power common shares after the Plan of Arrangement. Based on the number of Atlantic Power common shares outstanding immediately prior to the Effective Date and excluding any common shares of Atlantic Power that may be issued to finance the cash portion of the purchase price under the Plan of Arrangement, Atlantic Power estimates that upon completion of the Plan of Arrangement current Atlantic Power shareholders will own approximately 70% of the Combined Company and former CPILP unitholders will own approximately 30% of the Combined Company, in each case on a fully-diluted basis.

        Under the Plan of Arrangement, Atlantic Power will indirectly acquire the 16,513,504 CPILP units held by CPI Investments and the General Partner through the acquisition of all of the outstanding shares of CPI Investments from Capital Power L.P. and EPCOR.

        Pursuant to the Plan of Arrangement, all of the shares of CPI Investments held by EPCOR will be transferred to Atlantic Power in exchange for C$1.00 in cash and all of the shares of CPI Investments held by Capital Power L.P. will be transferred to Atlantic Power in exchange for aggregate consideration comprised of (i) a non-interest bearing promissory note (the "Purchaser Note") to be issued by Atlantic Power in favor of Capital Power L.P. in the principal amount of C$121,405,211, and (ii) either (A) the Cash Consideration or (B) the Share Consideration, as elected or deemed to be elected by Capital Power L.P. Atlantic Power will subsequently, as part of the Plan of Arrangement, pay C$121,405,211 to Capital Power L.P. in satisfaction in full of the Purchaser Note.

        If Capital Power L.P. elects to receive Cash Consideration, then, in addition to the C$121,405,211 payable in satisfaction of the Purchaser Note, it shall receive cash equal to (i) the product of (A) the Cash Consideration per CPILP unit and (B) the number of CPILP units held by CPI Investments and the General Partner, (ii) less the principal amount of the Purchaser Note, subject to proration as described under "The CPILP Special Meeting—Procedures for the Surrender of Unit Certificate and Receipt of Consideration—Letter of Transmittal and Election Form—Proration Provisions" beginning on page 44.

        If Capital Power L.P. elects to receive Share Consideration, then, in addition to the C$121,405,211 payable in satisfaction of the Purchaser Note, it shall receive that number of Atlantic Power common shares equal to (i) the product of (A) 1.3 and (B) the number of CPILP units held by CPI Investments and the General Partner, (ii) less the product of (A) the principal amount of the Purchaser Note divided by the Cash Consideration per CPILP unit and (B) 1.3, subject to proration as described under "The CPILP Special Meeting—Procedures for the Surrender of Unit Certificate and Receipt of Consideration—Letter of Transmittal and Election Form—Proration Provisions" beginning on page 44.

Background of the Plan of Arrangement

        The provisions of the Arrangement Agreement are the result of negotiations conducted between representatives of CPILP, the General Partner, the Manager and Atlantic Power and their respective

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financial and legal advisors. The following is a summary of the principal events leading up to the settlement of the Arrangement Agreement and related transaction documents and the meetings, negotiations, discussions and actions between the parties that preceded the public announcement of the execution of the Arrangement Agreement.

        At CPILP's annual strategic review meeting on June 7, 2010, the Manager delivered a presentation to the board of directors of the General Partner which questioned the status quo relationship between the Manager and CPILP, whereby the Manager (being two subsidiaries of Capital Power) was engaged by the General Partner to perform all of the management, employment and administrative services for CPILP and to operate and maintain all of CPILP's facilities pursuant to various management and operating agreements. Specifically, the Manager advised the board of directors of the General Partner that Capital Power was considering divesting itself of all of its CPILP interests in order to focus on its own core business. In this context, the Manager shared with the board of directors of the General Partner its preliminary analysis of strategic alternatives for CPILP, ultimately focusing on three: (i) internalization of management; (ii) merger with or sale to a third party; or (iii) purchase of CPILP by Capital Power. The Manager communicated Capital Power's commitment to continue managing CPILP to the best of its abilities and in accordance with the terms in the Management Agreements until the relationship was modified. The Manager also indicated that Capital Power would not be interested in acquiring CPILP.

        Following this, the board of directors of the General Partner resolved to form the Special Committee comprised of members of the board who are considered to be independent and not related to the Manager or Capital Power, being Messrs. Francois Poirier (Chair), Brian Felesky, Allen Hagerman and Rod Wimer. The Special Committee's purpose was, among other things, to review and consider potential alternatives for the restructuring of the relationship between the Manager and CPILP and, if and when appropriate, to review and negotiate the terms and conditions of any transaction involving CPILP which may result.

        Following the board meeting, the Special Committee met to discuss the Manager's preliminary analysis of alternatives. The Special Committee retained Greenhill as its independent financial advisor and McCarthy Tétrault LLP as its independent legal advisor. The Special Committee also retained Roades Advisors LLC ("Roades") to provide additional independent business and financial due diligence support. Between June 8, 2010 and June 18, 2011 (being the last meeting prior to the public announcement of the signing of the Arrangement Agreement), the Special Committee in executing its mandate would meet more than 30 times, most often with its financial advisors and legal counsel present at such meetings.

        Throughout the summer of 2010, the Special Committee worked with its advisors to analyze a broad spectrum of strategic alternatives available to CPILP. The Special Committee directed its advisors to work with the Manager to analyze all reasonably viable alternatives including, but not limited to, the sale of CPILP to a third party, roll-up into Capital Power, a change in its distribution policy, one or more asset sales and/or the internalization of management.

        On June 28, 2010, Greenhill and Roades met with the Manager to discuss their respective views on strategic alternatives. At this meeting, Capital Power reiterated that it did not feel that the status quo was the best option for CPILP or Capital Power.

        On July 6, 2010, Greenhill made an initial presentation to the Special Committee. Greenhill noted that Capital Power's desire to terminate its relationship with CPILP raised a number of issues that needed to be carefully analyzed for each alternative to be considered. The Special Committee instructed Greenhill to carry out all analyses or preparatory work that it considered reasonably useful or necessary in connection with each potential alternative.

        On August 9, 2010, Greenhill delivered its preliminary evaluation of strategic alternatives to the Special Committee. One alternative that Capital Power proposed involved the exchange of certain of

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CPILP's assets for Capital Power's partnership units. At the Special Committee's request, Greenhill examined a variety of asset swap scenarios. Based partially on Greenhill's examination, the Special Committee came to the preliminary conclusion that this alternative was unlikely to be in the best interests of CPILP and would, among other things, have a negative impact on CPILP's distribution sustainability. The other alternatives considered by Greenhill included maintaining the status quo and the internalization of management. With respect to this latter alternative, it was determined that, based on its preliminary analysis, the prospect of identifying and recruiting a credible management team would be time-consuming, may not ultimately be successful and would create uncertainty for CPILP in the meantime.

        Over the next two months, the Special Committee and its advisors continued to conduct financial and legal analysis on various strategic alternatives. During this same period, the Special Committee and Capital Power met periodically to discuss the status of the Special Committee's strategic review process. On August 16, 2010, Messrs. Poirier and Hagerman met with Messrs. Vaasjo and Lee from Capital Power to discuss the Special Committee's preliminary view that pursuing a sale or merger transaction would be in CPILP's best interest. These same parties, and their respective financial advisors, met again on numerous occasions throughout September 2010 to discuss the most effective strategies to seek a successful sale or merger for CPILP. The parties worked collaboratively to align their interests on a number of issues in the event of a change of control transaction, including with respect to the treatment of the Management Agreements and CPILP's "right of first look" with respect to acquisition and disposition opportunities presented to it by Capital Power.

        On August 20, 2010, Standard and Poor's published a credit ratings report which indicated that it had downgraded CPILP from BBB+ (outlook negative) to BBB (outlook stable). The reduced rating reflected, among other things, Standard and Poor's view that CPILP's financial risk profile had weakened as a result of debt-financed growth and the expectation that improvement in the medium term was unlikely as CPILP continued to execute its growth plan.

        On October 1, 2010, the board of directors of the General Partner resolved to establish a strategic review sub-committee comprised of Messrs. Lee and Poirier. The strategic review sub-committee was to act in an administrative capacity only to investigate all available strategic alternatives in the best interests of CPILP. Notwithstanding the creation of the strategic review sub-committee, all material business and commercial decisions including, for example, the approval of a sale process, recommendation or rejection of any third party offer and any final unitholder recommendation, would be made by the Special Committee and the board of directors of the General Partner.

        On October 5, 2010, CPILP and Capital Power issued a joint press release announcing that CPILP would initiate a process to review its strategic alternatives. The board of directors of the General Partner retained Greenhill and CIBC as co-financial advisors, and Roades Advisors LLC for due diligence support. McCarthy Tétrault LLP continued to act as legal advisors to CPILP, with Fraser Milner Casgrain LLP (Canadian counsel) and K&L Gates LLP (US counsel) acting for the General Partner and the Manager.

        Under the direction of the board of directors of the General Partner, the strategic review sub-committee instructed its financial advisors to solicit indications of interest to acquire CPILP from a broad range of potential financial and strategic purchasers. With the assistance of the Manager and its advisors, CPILP and its advisors prepared a confidential information memorandum describing CPILP and its business. Greenhill and CIBC identified a list of over 60 prospective purchasers. These prospective purchasers were contacted by Greenhill and CIBC during the months of October and November 2010.

        Of those prospective purchasers contacted, 27 of them executed confidentiality agreements and received a confidential information memorandum and were invited to submit preliminary indicative offers. On or before November 30, 2010, nine parties, including Atlantic Power, had submitted

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indicative offers to acquire all of CPILP or a selection of its assets. Of these nine parties, three were invited to proceed to a further round of enhanced due diligence access.

        In order to facilitate their diligence review of CPILP and encourage the submission of more formal proposals, these three prospective purchasers were provided with access to an electronic data room containing detailed information regarding CPILP, and were also given access to certain of the Manager's personnel. Throughout this period, the strategic review sub-committee provided regular oversight and direction to CPILP's financial advisors. Informally, Mr. Poirier communicated regularly with the other members of the Special Committee to keep them informed about the status of the sales process.

        At meetings of the independent directors' committee (the same directors that make up the Special Committee) on both December 17 and December 30, 2010, Mr. Poirier provided a status update on the steps undertaken to date in the sale process.

        On January 17, 2011, the Special Committee met to discuss the uncertainty and timing issues surrounding the pending decision from the North Carolina Utilities Commission ("NCUC") pertaining to the Roxboro and Southport facilities in North Carolina (the "North Carolina facilities"), and its impact upon the sale process. At this meeting, Mr. Poirier and Greenhill also provided a further status update on the steps undertaken to date in the sale process.

        On January 27, 2011, CPILP issued a press release announcing the issuance of an Order of Arbitration by the NCUC relating to the PPAs for CPILP's North Carolina facilities with Progress Energy Inc. In the months following the release of the Order, CPILP and Progress Energy Inc. negotiated the PPAs within the scope provided in the NCUC ruling. By the middle of March 2011, CPILP and Progress Energy Inc. concluded an interim contract setting out the material terms upon which the PPAs would ultimately be based. In the meantime, the remaining interested parties were asked to submit alternative offers for CPILP, one of which included the North Carolina facilities and another which excluded those assets.

        On March 14, 2011, following their due diligence review period, two of the three parties, including Atlantic Power, submitted offers which included their respective comments on a draft form of the Arrangement Agreement. Atlantic Power's implied offer value was C$16.50 per outstanding CPILP unit and excluded the North Carolina assets. The strategic review sub-committee and its financial advisors reviewed each offer. At the request and direction of the strategic review sub-committee, Greenhill and CIBC continued discussions with both prospective purchasers regarding, among other things, offer price and the prospective purchasers' sources of financing. As a result of such discussions, Atlantic Power submitted a subsequent proposal on April 11, 2011 at an increased implied offer value of C$17.00 per outstanding CPILP unit, exclusive of the North Carolina assets. On April 26, 2011, Atlantic Power confirmed its implied offer value of C$17.00 per outstanding CPILP unit, exclusive of the North Carolina assets, and further indicated an implied offer value of C$18.50 per unit if the North Carolina assets were to be included. The other prospective purchaser elected not to amend its March 14, 2011 proposal.

        Neither prospective purchaser had a strategic interest in acquiring the North Carolina facilities and, at the time, there remained uncertainty surrounding the negotiations and finalized terms of the PPAs for these facilities. Accordingly, the formal offers from both of these prospective purchasers either excluded or attributed less than fair value to these assets. CPILP proposed that Capital Power should enter into negotiations with CPILP to acquire these assets as a way to facilitate the sale process. On May 2, 2011, the Special Committee met to discuss the terms upon which CPILP would be willing to negotiate the sale of the North Carolina assets to Capital Power.

        At this time, the strategic review sub-committee instructed the financial advisors to seek from Atlantic Power an enhancement to its April 26, 2011 offer (excluding the North Carolina facilities). On May 5, 2011, Atlantic Power submitted a further amended proposal outlining the terms upon which it

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would acquire CPILP (excluding the North Carolina facilities) for an implied offer value of C$17.50 per outstanding CPILP unit. Atlantic Power requested that CPILP commit to exclusive negotiations with Atlantic Power for a 21 day period. After consideration of the merits of acceding to this request, CPILP, the Manager and CPI Investments entered an Exclusivity Agreement dated May 9, 2011 with Atlantic Power.

        On May 6, 2011, the strategic review sub-committee and its financial and legal advisors met with Atlantic Power and its financial and legal advisors in Toronto. At this meeting, the parties discussed, among other things, the Exclusivity Agreement, Atlantic Power's proposed plan to finance the acquisition of CPILP and the overall transaction structure and timing.

        In order to facilitate CPILP's due diligence review of Atlantic Power, CPILP, the Manager and Capital Power entered into a confidentiality agreement dated May 6, 2011 with Atlantic Power. On May 11, 2011, the Special Committee met with its advisors to receive an update on the due diligence performed to date on Atlantic Power. Financial due diligence on Atlantic Power was performed by the Manager and the financial advisors, with support from Roades Advisors LLC. Legal due diligence on Atlantic Power was performed on behalf of the General Partner by the Manager's counsel, Fraser Milner Casgrain LLP and K&L Gates LLP, with oversight and support from CPILP's counsel, Ogilvy Renault LLP and Richard A. Shaw Professional Corporation (CPILP's new counsel). The Special Committee discussed the appropriateness of the Manager and its advisors conducting due diligence on behalf of CPILP. At this same meeting, the Special Committee also discussed the progress of negotiations with Capital Power to acquire CPILP's North Carolina facilities.

        Over the ensuing weeks, both CPILP and Atlantic Power and their respective advisors conducted detailed due diligence reviews of the other's business, financial models and legal structures and commitments. A number of meetings took place between CPILP and its advisors and representatives of Atlantic Power and its advisors, during which information regarding each entity and its business and operations was shared, and the proposed terms of a transaction between the parties were discussed. During this same period, the Manager, on behalf of the General Partner, and CPILP and their legal advisors, Fraser Milner Casgrain LLP and Ogilvy Renault LLP, respectively, continued to negotiate the terms of the Plan of Arrangement and the Arrangement Agreement with Atlantic Power and its legal counsel, Goodmans LLP.

        On May 20, 2011, Greenhill and CIBC provided the Special Committee with a process and due diligence update. There was also a thorough discussion about financial analyses of both CPILP and Atlantic Power, particularly in the context of Atlantic Power's offer which included a mixture of cash and equity. The financial advisors were instructed to refine their analysis in this regard, as more information about Atlantic Power became available through the due diligence process.

        On May 26, 2011, the strategic review sub-committee and its financial and legal advisors met in Toronto with Atlantic Power and its financial and legal advisors to further negotiate the terms and timing of a potential transaction.

        On May 30, 2011, the board of directors of the General Partner met to receive an updated report from Greenhill and CIBC with respect to negotiations to date with Atlantic Power. At that meeting, it was resolved to extend the exclusivity period for discussions with Atlantic Power. Accordingly, effective May 30, 2011, CPILP, the Manager and CPI Investments agreed to extend the Exclusivity Agreement for a further 14 days, to expire on June 13, 2011. In the following two weeks, representatives of Atlantic Power and its outside financial and legal advisors and other consultants, and representatives of CPILP and its outside financial and legal advisors and other consultants, continued their respective due diligence investigations, including in relation to CPILP's pension liabilities, financial, legal, environmental and operational matters and potential synergies.

        On June 2, 2011, the Special Committee asked its legal advisors to review the legal duties and standards for directors to follow in the context of the Arrangement. There was a discussion about

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various governance issues, including further discussions of the appropriateness of CPILP relying upon the due diligence performed by the Manager and its advisors.

        On June 3, 2011, Atlantic Power's senior management made a presentation to the board of directors of the General Partner in Calgary regarding Atlantic Power and its view of the anticipated strategic, financial and operational characteristics of the Combined Company. At this same meeting, Atlantic Power alerted CPILP to the prospect of a credit rating for the Combined Company that may be lower than that of CPILP. The parties also made progress in their discussions regarding the contractual and other business terms of a transaction. These discussions included the scope of the support agreements to be provided by each of Capital Power LP and EPCOR, the prospect that Capital Power would agree to a lock-up of any Atlantic Power shares it received as a result of the Plan of Arrangement, the terms of Atlantic Power's bridge financing commitment and a number of other terms that affected transaction certainty.

        During a meeting on June 10, 2011, Atlantic Power informed CPILP that it intended to lower its offer price by $0.50 from $17.50 to $17.00 based on its due diligence findings, specifically, a newly-provided amendment to a PPA that was inconsistent with Atlantic Power's then-current model. The strategic review sub-committee met with its financial and legal advisors to discuss the implications of this information, in addition to the prospect of a credit ratings downgrade in the Combined Company.

        On June 11, 2011, the Special Committee met with its legal advisors to review the status of negotiations with Atlantic Power. At this meeting, there was considerable discussion about the terms upon which CPILP would sell the North Carolina facilities to Capital Power, and the impact of that disposition upon a transaction with Atlantic Power for the remainder of CPILP. There was also a significant discussion about Atlantic Power's proposed reduction to the purchase price.

        On June 15, 2011, the strategic review sub-committee and its financial and legal advisors met in Toronto with Atlantic Power and its financial and legal advisors to further negotiate the terms of a potential transaction. At this meeting, a broad list of issues were discussed including each parties' outstanding due diligence items, allocation of severance and pension deficit obligations, the scope of transitional services that would be required and the status of the legal documentation needed to consummate the Plan of Arrangement and the related transactions. Atlantic Power also provided the strategic review sub-committee and its advisors with the initial draft commitment letters in connection to the proposed bridge financing in support of the Plan of Arrangement. At the meeting, the terms and conditions of these commitment letters were reviewed in detail. There was also considerable discussion around Capital Power's acquisition of the North Carolina facilities, as well as Atlantic Power's request for a lock-up agreement from Capital Power to the extent that it received Atlantic Power common shares as consideration for its units. Over the course of the meeting, the parties and their respective advisors developed tentative agreement on each of the outstanding issues and were ultimately able to settle upon indicative terms pursuant to which Capital Power would acquire the North Carolina assets for an implied value of C$2.15 per CPILP unit, and Atlantic Power would acquire all of the CPILP units for an implied value of C$17.25 per unit, for a total implied value of C$19.40 per CPILP unit.

        On June 16, 2011, the board of directors of the General Partner met with their financial and legal advisors to receive an update on the transaction with Atlantic Power, as well as to discuss the preliminary version of the due diligence report prepared by the Manager and its advisors. The meeting also discussed Atlantic Power's proposed bridge financing commitment, involving up to C$400 million to be drawn by CPILP, and its potential impact upon the credit profile and exposure of CPILP's existing debt instruments. In particular, the board of directors of the General Partner were particularly concerned about how the proposed bridge financing might impact the ability of CPILP and CPI Preferred Equity Ltd. to meet their respective payment obligations. In this regard, it was determined that Atlantic Power would be asked to provide parental guarantees to the payment obligations for the public debtholders at CPILP (medium term notes) in the event the portion of the bridge financing to be drawn by CPILP was drawn, and CPI Preferred Equity Ltd. (preferred shares). At this board

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meeting, representatives of Greenhill and CIBC reviewed with the board their financial analyses with respect to Atlantic Power and the proposed Arrangement. Each of Greenhill and CIBC also rendered oral versions of their respective opinions to the Special Committee with respect to the fairness, from a financial point of view, to the holders of CPILP units (other than the General Partner, CPI Investments and Atlantic Power in respect of the Greenhill opinion and other than Capital Power and its affiliates in respect of the CIBC opinion) of the consideration to be received by such holders pursuant to the Arrangement Agreement. Finally, the board discussed a likely timetable for the completion of the remaining items in relation to the execution of the Arrangement Agreement and related materials.

        On June 18, 2011, the Special Committee met with its financial and legal advisors, as well as the Manager's legal advisor, to review the status of the key transaction documents including the Arrangement Agreement and the support agreements. At the meeting, the Special Committee's legal advisors reviewed the legal duties imposed upon the directors in the circumstances, and Greenhill and CIBC made presentations with respect to their respective fairness opinions and supporting analyses. The Special Committee spent a considerable amount of this meeting reviewing with its advisors the impact of the Plan of Arrangement upon CPILP's stakeholders including, but not limited to, the unitholders, public debtholders, preferred shareholders and creditors and employees.

        On June 19, 2011, the board of directors of the General Partner met to consider the terms of the Arrangement Agreement, at which meeting representatives of CPILP's and the Manager's financial and legal advisors were present. At this meeting, Fraser Milner Casgrain LLP reviewed the key elements of the transaction documents, with a focus on the deal protection provisions in each such document. After the meeting, the Special Committee went in camera with its financial and legal advisors.

        During its in camera session, at the request of the Special Committee, Greenhill and CIBC each confirmed that nothing had occurred that would alter either of its financial analysis that was presented on June 16, 2011. Greenhill and CIBC also confirmed that they would deliver their respective written fairness opinions as of this date. Representatives of Norton Rose OR LLP (successor of Ogilvy Renault LLP) and Richard A. Shaw Professional Corporation reviewed for the Special Committee the terms of the Arrangement Agreement and the conduct of the negotiations to that point in time. Members of the Special Committee, with the assistance of their legal and financial advisors, reviewed and discussed the terms of the Arrangement Agreement and the process for completing the transaction. After a thorough review and discussion, the Special Committee resolved unanimously to recommend that the board of directors of the General Partner approve the Arrangement Agreement and the Plan of Arrangement, authorize CPILP to enter into the Arrangement Agreement and recommend that unitholders vote in favor of the Plan of Arrangement.

        Following the conclusion of the Special Committee's in camera session, the board of directors of the General Partner reassembled to receive the report of the Special Committee. The Special Committee reported that Greenhill and CIBC reviewed and discussed its financial analyses with respect to Atlantic Power and the proposed Plan of Arrangement and rendered their respective opinions to the Special Committee with respect to the fairness, from a financial point of view, to the holders of CPILP units (other than Capital Power, CPI Investments and Atlantic Power), of the consideration to be received by such holders pursuant to the Arrangement Agreement. The Special Committee further reported that it had reviewed the definitive agreements with counsel and, following its review and deliberations, was recommending that the board of directors of the General Partner approve and authorize CPILP to enter into the Arrangement Agreement and recommend to unitholders that they vote in favor of the transaction at a special unitholders meeting to be convened. At this point, the CPC-elect directors recused themselves and left the board meeting. After a further discussion, and consideration of the advice received from its financial and legal advisors, the board of directors of the General Partner resolved (with Messrs. Vaasjo, Lee, Oosterbaan and Brown abstaining) to approve the Plan of Arrangement and to recommend to unitholders that they vote in favor of the Plan of Arrangement.

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        Later that day and into the following morning, the Arrangement Agreement, the support agreements, the Management Agreement Termination Agreement, the Management Agreement Assignment Agreement, Membership Interest Purchase Agreement with respect to the North Carolina facilities, the Employee Hiring Agreement and the Pension Transfer Agreement were finalized and executed by the appropriate parties.

        Prior to the opening of the North American financial markets on June 20, 2011, Atlantic Power and CPILP issued a joint press release announcing the execution of the Arrangement Agreement and related aspects of the Plan of Arrangement.

Atlantic Power's Reasons for the Arrangement Agreement; Recommendations of Atlantic Power's Board of Directors

        At a meeting held on June 19, 2011, Atlantic Power's board of directors, unanimously determined that the Arrangement and the other transactions contemplated by the Arrangement Agreement, including the issuance of Atlantic Power common shares to CPILP unitholders necessary to complete the Arrangement, are in the best interests of Atlantic Power and is fair to its stakeholders. Accordingly, the Atlantic Power board of directors unanimously recommends that the Atlantic Power shareholders vote "FOR" the Share Issuance Resolution. In reaching these determinations, the Atlantic Power board of directors consulted with Atlantic Power's management and its legal, financial and other advisors, and also considered numerous factors, including the following factors which the Atlantic Power board of directors viewed as supporting its decisions:

        Strategic Benefits of the Plan of Arrangement.    The Atlantic Power board of directors believes that the combination of Atlantic Power and CPILP should result in significant strategic benefits to the Combined Company, which benefits would accrue to Atlantic Power's shareholders, as shareholders of the Combined Company, and to the Combined Company. These strategic benefits include the following:

        Financial Benefits of the Plan of Arrangement.    The Atlantic Power board of directors believes that the combination of Atlantic Power and CPILP should result in significant financial benefits to Atlantic Power's shareholders and the Combined Company. These financial benefits include the following:

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        Other Factors Considered.    During the course of its deliberations relating to the Arrangement Agreement and Plan of Arrangement, Atlantic Power's board of directors considered the following factors in addition to the benefits described above, which, taken together, supported proceeding with the transaction:

        The Atlantic Power board of directors weighed these factors against a number of uncertainties, risks and potentially negative factors relevant to the Plan of Arrangement, including:

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        Atlantic Power's board of directors further considered the proposed form of consideration to be received by CPILP unitholders pursuant to the Plan of Arrangement and the ways in which Atlantic Power would finance the payment of the consideration. Atlantic Power's board of directors consulted with Atlantic Power's management and its legal, financial and other advisors and determined that an all-cash transaction would not be optimal for Atlantic Power since it would need to raise substantially the full amount of the consideration payable under the Plan of Arrangement by either borrowings under new or existing credit facilities and/or in one or more capital markets transactions. Raising that much cash over so short a period, even if possible, would also result in Atlantic Power incurring an overall higher cost of capital in the way of fees, commissions and expenses of the borrowings and/or offerings. In addition, an all-cash transaction would be immediately taxable to CPILP unitholders, whereas eligible holders that received Atlantic Power common shares pursuant to a plan of arrangement would be entitled to make a joint tax election that would, depending on the circumstances of each particular CPILP unitholder, allow for a full or partial deferral of taxable gains that would otherwise be realized. Accordingly, under the Plan of Arrangement as ultimately approved by Atlantic Power's board of directors, CPILP unitholders could elect to receive either C$19.40 in cash or 1.3 Atlantic Power common shares for each CPILP unit held but all cash elections would be subject to proration if total cash elections exceed approximately C$506.5 million, setting a maximum on the aggregate amount of cash Atlantic Power would need to complete the Plan of Arrangement. Likewise, all share elections would be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares, thereby setting a maximum on the number of Atlantic Power common shares that could be issued under the Plan of Arrangement.

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        Overall, Atlantic Power's board of directors concluded that the uncertainties, risks and potentially negative factors relevant to the Plan of Arrangement were outweighed by the potential benefits that it expected Atlantic Power would achieve as a result of the Plan of Arrangement, each as discussed above.

        This discussion of the information and factors considered by Atlantic Power's board of directors includes the principal positive and negative factors considered by the Atlantic Power board of directors, but is not intended to be exhaustive and may not include all of the factors considered by the Atlantic Power board of directors. In view of the wide variety of factors considered in connection with its evaluation of the Plan of Arrangement and the other transactions contemplated in connection with the Plan of Arrangement, and the complexity of these matters, Atlantic Power's board of directors did not find it useful and did not attempt to quantify or assign any relative or specific weights to the various factors that it considered in reaching its determination to approve the Plan of Arrangement and the other transactions contemplated in connection with the Plan of Arrangement and to make its recommendations to Atlantic Power shareholders. Rather, Atlantic Power's board of directors viewed its decisions as being based on the totality of the information presented to it and the factors it considered. In addition, individual members of Atlantic Power's board of directors may have given differing weights to different factors. It should be noted that this explanation of the reasoning of the Atlantic Power board of directors and certain information presented in this section is forward-looking in nature and, therefore, that information should be read in light of the factors discussed in the section entitled "Cautionary Note Regarding Forward-Looking Statements" in this joint proxy statement, beginning on page 30.

Opinions of Atlantic Power's Financial Advisors

Opinion of TD Securities Inc.

        On June 19, 2011, TD Securities rendered to Atlantic Power's board of directors its opinion that on such date and based upon and subject to the limitations, qualifications and assumptions set forth in the written opinion, the Consideration to be paid by Atlantic Power in connection with the transaction contemplated by the Arrangement Agreement (the "Proposed Transaction") was fair, from a financial point of view, to Atlantic Power (the "TD Securities Fairness Opinion").

        The full text of the written fairness opinion of TD Securities, dated June 19, 2011, is attached to this joint proxy statement as Annex B. The opinion sets forth, among other things, the assumptions made, procedures followed, matters considered and qualifications and limitations on the scope of the review undertaken by TD Securities in rendering its opinion. You should read the entire opinion carefully and in its entirety. TD Securities Inc.'s opinion is directed to Atlantic Power's board of directors and addresses only the fairness from a financial point of view of the Consideration to be paid by Atlantic Power in connection with the Proposed Transaction as at the date of the opinion. It does not address any other aspect of the Proposed Transaction and does not constitute a recommendation to the shareholders of Atlantic Power or unitholders of CPILP as to how to vote with respect to the Plan of Arrangement or any other matter. In addition, the opinion does not in any manner address the prices at which Atlantic Power common shares will trade following the consummation of the Plan of Arrangement. The summary of the opinion of TD Securities set forth in this joint proxy statement is qualified in its entirety by reference to the full text of the opinion.

        In connection with the TD Securities Fairness Opinion, TD Securities reviewed (where applicable) and relied upon (without attempting to verify independently the completeness, accuracy, or fair presentation of) or carried out, among other things, the following:

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        With Atlantic Power's acknowledgement and agreement, TD Securities relied upon and assumed the accuracy, completeness and fair presentation of all data, documents, advice, opinions and other information obtained by it from public sources (including on SEDAR) or provided to it by or on behalf of Atlantic Power and/or CPILP and/or their respective personnel, consultants and advisors, or otherwise obtained by TD Securities, including the certificate dated June 19, 2011 from a senior officer of Atlantic Power and all other documents and information referred to above (collectively, the "Data"). The TD Securities Fairness Opinion is premised and conditional upon such accuracy, completeness and fair presentation and upon there being no "misrepresentation" (as defined in the Securities Act (Ontario)) in the Data. In addition, TD Securities assumed that there is no information relating to the business, operations, assets, liabilities, condition (financial or otherwise), capital or prospects of Atlantic Power, CPILP or any of their respective affiliates that is or could reasonably be expected to be material to the TD Securities Fairness Opinion that was not disclosed or otherwise made available to TD Securities as part of the Data. Subject to the exercise of professional judgment and except as expressly described in the TD Securities Fairness Opinion, TD Securities did not attempt to verify independently the accuracy, completeness or fair presentation of any of the Data.

        With respect to the budgets, forecasts, projections or estimates provided to TD Securities and used in its analyses, TD Securities noted that projecting future results is inherently subject to uncertainty. TD Securities assumed, however, that such budgets, forecasts, projections and estimates were prepared using the assumptions identified therein (as discussed between senior management of Atlantic Power and TD Securities) which TD Securities was advised are (or were at the time of preparation and continue to be), in the opinion of Atlantic Power, reasonable in the circumstances. In addition, TD Securities assumed that the expected synergies will be achieved at the times and in the amounts projected by Atlantic Power. TD Securities expressed no independent view as to the reasonableness of such budgets, forecasts, projections and estimates and the assumptions on which they are based.

        TD Securities was not engaged to review and did not review any of the legal, accounting or tax aspects of the Proposed Transaction. In preparing the TD Securities Fairness Opinion, TD Securities assumed that the Proposed Transaction complies with all applicable laws and accounting requirements and has no adverse tax or other adverse consequences for Atlantic Power.

        In preparing the TD Securities Fairness Opinion, TD Securities made several assumptions, including that all final executed versions of agreements and documents relating to the Proposed Transaction will conform in all material respects to the drafts provided to or terms discussed with TD Securities, all conditions to the completion of the Proposed Transaction can and will be satisfied in due course, that all consents, permissions, exemptions or orders of relevant regulatory authorities or third parties will be obtained, without adverse condition or qualification, and that the actions being taken and procedures being followed to implement the Proposed Transaction are valid and effective and comply with all applicable laws and regulatory requirements. In its analysis in connection with the preparation of the TD Securities Fairness Opinion, TD Securities made numerous assumptions with respect to industry performance, general business and economic conditions, and other matters, many of which are beyond the control of TD Securities, Atlantic Power, CPILP or their respective affiliates. Among other things, TD Securities assumed the accuracy, completeness and fair presentation of and relied upon the financial statements forming part of the Data. The TD Securities Fairness Opinion is conditional on all such assumptions being correct.

        The TD Securities Fairness Opinion is directed to Atlantic Power's board of directors and is not intended to be, and does not constitute, a recommendation that Atlantic Power shareholders vote in favor of the Proposed Transaction or as an opinion concerning the trading price or value of any securities of Atlantic Power following the announcement or completion of the Proposed Transaction. The TD Securities Fairness Opinion does not address the relative merits of the Proposed Transaction as compared to other transactions or business strategies that might be available to Atlantic Power, nor does it address the underlying business decision to implement the Proposed Transaction. In preparing

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the TD Securities Fairness Opinion TD Securities did not consider the economic or other interests of either individual, or particular groups of, Atlantic Power stakeholders. The TD Securities Fairness Opinion was rendered as of June 19, 2011, on the basis of securities markets, economic and general business and financial conditions prevailing on that date and the condition and prospects, financial and otherwise, of Atlantic Power and CPILP and their respective subsidiaries and affiliates as they were reflected in the Data provided or otherwise available to TD Securities. Although TD Securities reserved the right to change, modify, update, supplement or withdraw the TD Securities Fairness Opinion in the event that there is any material change in any fact or matter affecting the TD Securities Fairness Opinion, it disclaims any undertaking or obligation to advise any person of any such material change that may come to its attention or to change, modify, update, supplement or withdraw the TD Securities Fairness Opinion as a result of any such material change. TD Securities did not undertake an independent evaluation, appraisal or physical inspection of any assets or liabilities of Atlantic Power or CPILP or their respective subsidiaries. TD Securities is not an expert on, and did not render advice to the Board of Directors of Atlantic Power regarding, legal, accounting, regulatory or tax matters.

        The following is a brief summary of the material analyses performed by TD Securities in connection with its oral opinion and the preparation of its written opinion letter dated June 19, 2011. Some of these summaries of financial analyses include information presented in tabular format. In order to understand fully the financial analyses used by TD Securities, the tables must be read together with the text of each summary. The tables alone do not constitute a complete description of the financial analyses.

Historical Share Price Analysis

        TD Securities reviewed the share price performance of Atlantic Power and CPILP for various periods ending on June 17, 2011 (the last trading day prior to the meeting of the Board of Directors of Atlantic Power approving the execution of the Arrangement Agreement) as observed on the Toronto Stock Exchange (TSX) and other Canadian exchanges as reported by Bloomberg L.P. TD Securities noted that the range of low and high closing prices of Atlantic Power common shares during the prior 60-day period was C$13.96 to C$15.19. TD Securities noted that the range of low and high closing prices of CPILP units during the prior 60-day period was C$18.28 to C$20.90. The consideration (C$19.42 assuming the closing price C$14.96 for Atlantic Power common shares on the TSX on June 17, 2011) represented a 4.2% premium to the closing price of CPILP units on June 17, 2011.

Equity Research Analyst Price Targets

        TD Securities reviewed the public market trading price targets for Atlantic Power common shares prepared and published by equity research analysts between May 12, 2011 and May 27, 2011. These targets reflected each analyst's estimate of the 12-month target trading price of Atlantic Power common shares. TD Securities noted that the range of 12-month research analyst price targets for Atlantic Power was C$12.00 to C$15.00 per share. Using a discount rate of 9%, TD Securities discounted the analysts' price targets back 12-months to arrive at a range of present values for these targets. TD Securities' analysis of the present value of equity research analysts' future price targets implied an equity range for Atlantic Power of approximately $11.01 to $13.76 per share.

        TD Securities reviewed the public market trading price targets for CPILP units prepared and published by equity research analysts between April 28, 2011 and June 13, 2011. These targets reflected each analyst's estimate of the 12-month target trading price of CPILP units. TD Securities noted that the range of 12-month research analyst price targets for CPILP was C$16.50 to C$20.00 per unit. Using a discount rate of 9%, TD Securities discounted the analysts' price targets back 12-months to arrive at a range of present values for these targets. TD Securities' analysis of the present value of equity

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research analysts' future price targets implied an equity range for CPILP of approximately C$15.14 to C$18.35 per unit.

        The public market trading price targets published by equity research analysts do not necessarily reflect current market trading prices for Atlantic Power common shares and CPILP units and these estimates are subject to uncertainties, including the future financial performance of Atlantic Power and CPILP and future financial market conditions.

Comparable Company Analysis

        TD Securities performed a comparable company analysis, which is designed to provide an implied value of a company by comparing it to similar companies. TD Securities compared certain financial information of Atlantic Power and CPILP with publicly-available information for peer group companies and funds that operate in and are exposed to similar lines of business as Atlantic Power and CPILP, namely Canadian-traded independent power producers. The peer group included:

        For this analysis, TD Securities considered the ratio of enterprise value (defined as equity value plus total debt, minority interest, capital lease obligations and preferred shares less cash and cash equivalents, referred to as EV) to 2011 estimated earnings before interest, taxes, depreciation and amortization (referred to as EBITDA), EV/EBITDA, to be the primary value multiple when analyzing each of these companies or funds. Based on estimates for the peer group companies or funds provided by the Institutional Brokers' Estimate System (I/B/E/S), and public filings, TD Securities calculated the relevant metrics for each of the comparable companies or funds. TD Securities selected, using its experience and judgment, a representative range of EV/EBITDA multiples of the comparable companies or funds and applied this range of multiples to the relevant financial statistics for Atlantic Power and CPILP. For purposes of estimated 2011 EBITDA, TD Securities utilized consensus metrics provided by I/B/E/S, as well as estimates prepared by Atlantic Power management.

        TD Securities calculated the implied equity range for Atlantic Power common shares as follows:

 
  Estimated
2011
EBITDA
(C$MM)
  EV/EBITDA
Multiple
Range
  Implied Range Per
Atlantic Power
Common Share

I/B/E/S Consensus

  C$ 133     10.0x - 11.0x   C$10.40 - $12.34

Atlantic Power Management

  C$ 147     10.0x - 11.0x   C$12.43 - $14.57

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        TD Securities calculated the implied equity range per CPILP unit as follows:

 
  Estimated
2011
EBITDA
(C$MM)
  EV/EBITDA
Multiple
Range
  Implied Range Per
CPILP Unit
 

I/B/E/S Consensus

  C$ 187     10.0x - 11.0x   C$ 17.79 - $21.10  

Atlantic Power Management

  C$ 174     10.0x - 11.0x   C$ 17.51 - $20.58  

        The process of analyzing EV/EBITDA multiples implied by comparable publicly traded companies or funds and applying these EV/EBITDA multiples to Atlantic Power and CPILP involved certain judgments concerning the financial and operating characteristics of the peer group compared to Atlantic Power and CPILP. Given differences in business mix, growth prospects and risks inherent in the comparable companies or funds identified, TD Securities did not consider any specific company to be directly comparable to Atlantic Power or CPILP.

Precedent Transaction Analysis

        Using publicly-available information, TD Securities reviewed the terms of selected precedent transactions in which the targets were Canadian independent power producers, such as Atlantic Power and CPILP.

        TD Securities reviewed the consideration given and calculated the ratio of EV to EBITDA ("EV/EBITDA Multiple").

        For this analysis, TD Securities reviewed the following transactions:

Acquiror
  Target   Announcement
Date
 

Boralex Inc. 

  Boralex Power Income Fund     05/03/2010  

Innergex Power Income Fund

  Innergex Renewable Energy Inc.     02/01/2010  

Northland Power Income Fund

  Northland Power Inc.     04/23/2009  

FPL Energy, LLC

  Creststreet Power & Income Fund LP     04/18/2008  

Cheung Kong Infrastructure Holdings Ltd. 

  TransAlta Power, LP     10/15/2007  

Fort Chicago Energy Partners LP

  Countryside Power Income Fund     06/20/2007  

Macquarie Power & Infrastructure Income Fund

  Clean Power Income Fund     04/15/2007  

Harbinger Capital Partners

  Calpine Power Income Fund     01/29/2007  

EPCOR Utilities Inc. 

  TransCanada Power L.P. (30.6% interest in public units and control of the General Partner)     05/17/2005  

        Based on the analysis of the relevant characteristics for each of the selected precedent transactions and on the experience and judgment of TD Securities, TD Securities selected a representative range of EV/EBITDA Multiples of the selected precedent transactions and applied this range of multiples to the relevant EBITDA estimates for CPILP.

        TD Securities calculated the implied equity range per CPILP unit as follows:

 
  Estimated
2011
EBITDA
(C$MM)
  EV/EBITDA
Multiple
Range
  Implied Range Per
CPILP Unit

I/B/E/S Consensus

  C$ 187     9.5x - 11.0x   C$16.13 - $21.10

Atlantic Power Management

  C$ 174     9.5x - 11.0x   C$15.97 - $20.58

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        The process of analyzing EV/EBITDA Multiples implied by selected precedent transactions and applying these EV/EBITDA multiples to CPILP involved certain judgments concerning, among other things, the financial and operating characteristics of the companies or funds acquired in these transactions compared to the business of CPILP. Given the differences in business mix, economic and market conditions, growth prospects and risks inherent in the selected precedent transactions identified, TD Securities did not consider any specific selected precedent transaction to be directly comparable to CPILP.

Discounted Cash Flow Analysis

        TD Securities performed discounted cash flow (DCF) analysis on Atlantic Power and CPILP, which is an analysis of the present value of expected future cash flows. The DCF methodology reflects the growth prospects and risks inherent in each business by taking into account the amount, timing and relative certainty of projected free cash flows expected to be generated by each business. The DCF approach requires that certain assumptions be made regarding, among other things, future free cash flows, discount rates and terminal values. The possibility that some of the assumptions will prove to be inaccurate is one factor involved in the determination of discount rates to be used in establishing a range of values. TD Securities' DCF analysis of Atlantic Power and CPILP involved discounting to a present value the projected levered after tax free cash flows from January 1, 2012 until December 31, 2024 for each of Atlantic Power and CPILP, plus terminal values determined as at December 31, 2024, utilizing an appropriate cost of equity as the discount rate.

        TD Securities analyzed Atlantic Power's business through discussions with Atlantic Power management, a review of 2012 - 2024 financial forecasts prepared by Atlantic Power management and by using publicly-available information. The terminal value was calculated by applying a terminal year perpetual growth formula to 2025 free cash flow as projected by Atlantic Power management. The perpetual growth formula used a 0% terminal year growth rate and 8.5% - 9.5% was selected as the appropriate equity discount rate range. The discount rate range was selected based on an analysis of Atlantic Power's cost of equity. This analysis resulted in an implied equity range for Atlantic Power of C$9.49 - C$10.57 per share.

        TD Securities analyzed CPILP's business through discussions with both Atlantic Power and CPILP management, a review of 2012 - 2024 financial forecasts prepared by Atlantic Power management and by using publicly-available information. Atlantic Power management prepared two financial forecasts for CPILP. A low case and a high case incorporating the results of the due diligence performed by Atlantic Power on CPILP. Atlantic Power management also identified synergies related to the elimination of certain public company costs and efficient use of available tax deductions. The terminal value was calculated by applying a terminal year perpetual growth formula to 2025 free cash flow, as projected by Atlantic Power management. The perpetual growth formula used a 0% terminal year growth rate and 8.5% - 9.5% was selected as the appropriate equity discount rate range. The discount rate range was selected based on an analysis of CPILP's cost of equity. This analysis resulted in an implied equity range for CPILP of C$15.72 - C$19.33 per unit including synergies.

        TD Securities analyzed the implied value, using the DCF methodology described above, of Atlantic Power per common share on a pro forma basis, after giving effect to the Proposed Transaction. TD Securities assumed that Atlantic Power successfully completes the public market financings for the Proposed Transaction as contemplated at June 17, 2011. The public market financings contemplated at June 17, 2011 included, among other things, a term-debt issuance of approximately $430 million and an Atlantic Power public common share offering of approximately C$200 million. TD Securities performed its analysis using the low and high financial forecasts including the identified synergies above. The analysis resulted in an implied equity range for Atlantic Power on a pro forma basis, after giving effect to the Proposed Transaction of C$10.23 - C$12.52 per share including synergies.

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Distributable Cash Flow Accretion and Payout Ratio Analysis

        TD Securities performed distributable cash flow accretion analysis, which compares the projected cash flows available for distribution to common shareholders of Atlantic Power on a standalone and pro forma basis, using forecasts prepared by Atlantic Power management. Cash flow available for distribution is defined as cash from operations less maintenance capital expenditures and mandatory debt principal or amortization payments.

Distributable Cash Flow Per Share
  2011 - 2020 Average

Atlantic Power Standalone

  C$0.95

Pro Forma—Atlantic Power Management

  C$1.20 - C$1.29

        TD Securities performed payout ratio analysis, which is an analysis of the percentage resulting from the projected dividends paid to common shareholders of Atlantic Power compared to projected cash flows available for distribution to common shareholders on a standalone and pro forma basis, using forecasts prepared by Atlantic Power management, Atlantic Power standalone annual dividend per share used in the analysis was C$1.09 and the Atlantic Power pro forma annual dividend per share (under the low and high case) used in the analysis was C$1.15. The forecasted annual dividend per share, as a percentage of forecasted cash flow available for distribution per share, results in an implied forecasted payout ratio.

Payout Ratio
  2011 - 2020 Average

Atlantic Power Standalone

  124.9%

Pro Forma—Atlantic Power Management

  90.0% - 97.4%

Exchange Ratio Analysis

        TD Securities performed an analysis of the exchange ratio of CPILP units to Atlantic Power common shares, using the transaction consideration of C$19.42 (based on the closing price for Atlantic Power common shares on June 17, 2011) and the volume-weighted average prices of Atlantic Power's shares as at June 17, 2011 as observed on the Toronto Stock Exchange (TSX) and other Canadian exchanges as reported by Bloomberg L.P. This implied exchange ratios observed during these periods ranging from 1.29x to 1.33x Atlantic Power common shares per CPILP unit.


General

        In connection with the review of the Proposed Transaction by the board of directors of Atlantic Power, TD Securities performed a variety of financial and comparative analyses for purposes of rendering its opinion. The preparation of a financial opinion is a complex process and is not necessarily amenable to partial analysis or summary description. In arriving at its opinion, TD Securities considered the results of all of its analyses as a whole and did not attribute any particular weight to any single analysis or factor it considered. TD Securities believes that its analyses must be considered as a whole and that selecting portions of the analyses or the factors considered by it, without considering all factors and analyses together, could create an incomplete or misleading view of the process underlying the TD Securities Fairness Opinion. In addition, TD Securities may have given various analyses and factors more or less weight than other analyses and factors, and may have deemed various assumptions more or less probable than other assumptions. As a result, the ranges of implied values resulting from any particular analysis or combination of analyses described above should not be taken to be the view of TD Securities with respect to the actual value of Atlantic Power or CPILP. TD Securities has not prepared a valuation of Atlantic Power or CPILP or any of their respective securities or assets or liabilities and the Fairness Opinion should not be construed as such.

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        In performing its analyses, TD Securities made numerous assumptions with respect to industry performance, general business, regulatory, economic, market and financial conditions and other matters. Many of these assumptions are beyond the control of Atlantic Power and CPILP. Any estimates contained in TD Securities' analyses are not necessarily indicative of future results or actual values, which may be significantly more or less favourable than those suggested by such estimates.

        The analyses performed were prepared solely as part of TD Securities' analysis of the fairness of the Consideration to be paid by Atlantic Power in connection with the Proposed Transaction from a financial point of view to Atlantic Power, and were conducted in connection with the delivery of the TD Securities Fairness Opinion to the board of directors of Atlantic Power. These analyses do not purport to be appraisals or to reflect the prices at which shares of common stock of Atlantic Power or CPILP units might actually trade. The consideration to be paid to the holders of CPILP units and other terms of the Proposed Transaction were determined through arm's-length negotiations between Atlantic Power and CPILP and were approved by Atlantic Power's board of directors. TD Securities provided advice to Atlantic Power during such negotiations; however, TD Securities did not recommend any specific consideration to Atlantic Power or that any specific consideration constituted the only appropriate consideration for the Proposed Transaction. In addition, as described above, TD Securities' opinion and presentation to Atlantic Power's board of directors were one of many factors taken into consideration by such Board in making their decision to approve the Proposed Transaction. Consequently, the TD Securities analyses as described above should not be viewed as determinative of the opinion of Atlantic Power's board of directors with respect to the consideration or the value of CPILP, or of whether the board of directors of Atlantic Power would have been willing to agree to pay a different consideration. See the section entitled "Atlantic Power's Reasons for the Arrangement Agreement; Recommendations of Atlantic Power's Board of Directors" beginning on page 55.

        The TD Securities Fairness Opinion was approved by a committee of senior investment banking professionals of TD Securities in accordance with its customary practice.

        Atlantic Power retained TD Securities based upon TD Securities' qualifications, experience and expertise and its knowledge of the business affairs of Atlantic Power. Neither TD Securities, nor any of its affiliates is an insider, associate or affiliate (as those terms are defined in the Securities Act (Ontario)) of Atlantic Power, CPILP or any of their respective affiliates (collectively, the "Interested Parties"). Neither TD Securities nor any of its affiliates is an advisor to any Interested Party with respect to the Proposed Transaction, other than to Atlantic Power and its affiliates.

        TD Securities and its affiliates have not been engaged to provide any financial advisory services, have not acted as lead or co-lead manager on any offering of securities of Atlantic Power or any other Interested Party, or had a material financial interest in any transaction involving Atlantic Power or any other Interested Party during the 24 months preceding the date on which TD Securities was first contacted in respect of the Proposed Transaction other than services provided under its engagement in respect of the Proposed Transaction or as described hereinafter. TD Securities acted as a co-manager for the offering of Atlantic Power common shares and convertible debentures in October 2010. TD Securities acted as co-financial advisor, co-lead underwriter, lead arranger and co-lead arranger in connection with the initial public offering of common shares of Capital Power and the related reorganization and acquisition transactions involving EPCOR Utilities Inc. ("EPCOR") and Capital Power LP and related financings in 2009. TD Securities acted as financial advisor to EPCOR for two unrelated transactions during the 24 month period referenced above.

        No understanding or agreement exists between TD Securities and any Interested Party with respect to future financial advisory or investment banking business other than those that may arise as a result of the terms of its engagement in respect of the Proposed Transaction. TD Securities may in the future, in the ordinary course of its business, perform financial advisory or investment banking services for Atlantic Power, any other Interested Party or any of their respective associates. A Canadian chartered

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bank, the parent company of TD Securities, directly or through one or more affiliates may provide banking services, extend loans or credit, offer financial products or provide other financial services to Atlantic Power, any other Interested Party or any of its associates.

        TD Securities and its affiliates act as a trader and dealer, both as principal and as agent, in major financial markets and, as such, may have and may in the future have positions in the securities of Atlantic Power and/or any other Interested Party and/or their respective associates and, from time to time, may have executed or may execute transactions on behalf of Atlantic Power and/or any other Interested Party and/or their respective associates or other clients for which it may have received or may receive compensation. As an investment dealer, TD Securities conducts research on securities and may, in the ordinary course of its business, provide research reports and investment advice to its clients on investment matters, including matters with respect to the Proposed Transaction, Atlantic Power and/or any other Interested Party and/or their respective associates.

        Pursuant to the terms of its engagement, Atlantic Power Corp. ("Atlantic Power") has agreed to pay TD Securities Inc. ("TD Securities") a fee of $1,900,000, which became payable upon public announcement of the Proposed Transaction and upon delivery of the TD Securities Fairness Opinion and an additional fee of $5,600,000 that is payable upon consummation of the Proposed Transaction. Atlantic Power has also agreed to reimburse TD Securities for its fees and expenses incurred in performing its services. In addition, Atlantic Power has agreed to indemnify TD Securities and its affiliates, and each of their respective directors, officers, employees, partners, agents and shareholders against certain expenses, losses, claims, actions, suits, proceedings, damages and liabilities, including certain liabilities under the federal securities laws, related to, caused by, resulting from, arising out of or based on, directly or indirectly, TD Securities' engagement and any related transactions. TD Securities (jointly with Morgan Stanley) also entered into financing commitments to provide Atlantic Power with a $625 million senior secured credit facility in connection with the consummation of the Proposed Transaction, subject to the terms of such commitments, and pursuant to which TD Securities received customary fees. TD Securities has also been mandated as a joint bookrunner for any equity or debt offering related to the Proposed Transaction and pursuant to which TD Securities will be paid customary fees. In addition, TD Securities has provided certain services related to hedging foreign exchange exposure related to the Proposed Transaction pursuant to which TD Securities was paid customary fees. To the extent that Atlantic Power requires additional financing with respect to the Proposed Transaction, TD Securities and/or its affiliates may arrange and/or provide such additional financing and would expect to receive customary compensation.

        During the two years preceding the delivery of the opinion, TD Securities has provided certain investment banking services to Atlantic Power for which it has received customary compensation, including having acted as a co-manager on the issuance of $70 million aggregate principal of Atlantic Power Common Shares and $70 million aggregate principal of Atlantic Power Series B Convertible Debentures due 2017 in October, 2010.

Opinion of Morgan Stanley & Co. LLC

        Atlantic Power retained Morgan Stanley to provide it with financial advisory services and a financial opinion in connection with the transaction. Atlantic Power selected Morgan Stanley to act as its financial advisor based on Morgan Stanley's qualifications, expertise and reputation and its knowledge of the business and affairs of Atlantic Power. At the meeting of the Atlantic Power board of directors on June 19, 2011, Morgan Stanley rendered its oral opinion, subsequently confirmed in writing, that as of such date and based upon and subject to the various assumptions, considerations, qualifications and limitations set forth in its written opinion, the consideration to be paid by Atlantic Power pursuant to the Arrangement Agreement was fair, from a financial point of view, to Atlantic Power.

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        The full text of the written opinion of Morgan Stanley, dated June 19, 2011, which discusses, among other things, the assumptions made, procedures followed, matters considered, and qualifications and limitations of the review undertaken by Morgan Stanley in rendering its opinion, is attached as Annex C and incorporated by reference into this section of the joint proxy statement. The summary of the Morgan Stanley opinion provided in this joint proxy statement is qualified in its entirety by reference to the full text of the opinion. We encourage you to read the opinion carefully and in its entirety. The Morgan Stanley opinion is directed to the Atlantic Power board of directors and addresses only the fairness, from a financial point of view, of the consideration to be paid by Atlantic Power pursuant to the Arrangement Agreement. The Morgan Stanley opinion does not address any other aspect of the transaction and does not constitute a recommendation to any Atlantic Power shareholder or unitholder of CPILP as to how any such shareholder or unitholder should vote with respect to the proposed transaction or whether to take any other action with respect to the transaction. The opinion also does not address the prices at which Atlantic Power common shares will trade following the completion of the transaction or at any time.

        For the purposes of its opinion, Morgan Stanley, among other things:

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        In arriving at its opinion, Morgan Stanley assumed and relied upon, without independent verification, the accuracy and completeness of the information that was publicly available or supplied or otherwise made available to it by CPILP and Atlantic Power, and formed a substantial basis for its opinion. With respect to the CPILP Forecasts, Morgan Stanley assumed that they were reasonably prepared on bases reflecting the best currently available estimates and judgments of the management of CPILP of the future financial performance of CPILP. With respect to the Atlantic Power-CPILP Forecasts, the Atlantic Power Forecasts, and the Synergy/Cost Savings, Morgan Stanley assumed that they were reasonably prepared on bases reflecting the best currently available estimates and judgments of the management of Atlantic Power of the future financial performance of CPILP and Atlantic Power and the other matters covered thereby, and based on the assessments of the management of Atlantic Power as to the relative likelihood of achieving the future financial results reflected in the CPILP Forecasts and the Atlantic Power-CPILP Forecasts, Morgan Stanley relied, at the direction of Atlantic Power, on the Atlantic Power-CPILP Forecasts for purposes of its opinion. In addition, Morgan Stanley assumed that the Synergies/Cost Savings will be achieved at the times and in the amounts projected. In rendering its opinion, Morgan Stanley assumed that the final form of the Arrangement Agreement will not differ in any material respect from the draft reviewed by Morgan Stanley. In addition, Morgan Stanley assumed that the transaction will be consummated in accordance with the terms set forth in the Arrangement Agreement without any waiver, amendment or delay of any terms or conditions. Morgan Stanley assumed that in connection with the receipt of all the necessary governmental, regulatory or other approvals and consents required for the proposed transaction, no delays, limitations, conditions or restrictions will be imposed that would have a material adverse effect on the contemplated benefits expected to be derived in the proposed transaction.

        Morgan Stanley is a not a legal, tax or regulatory advisor. Morgan Stanley is a financial advisor only and it relied upon, without independent verification, the assessment of Atlantic Power and CPILP and their legal, tax or regulatory advisors with respect to legal, tax or regulatory matters. Morgan Stanley expressed no view on, and its opinion did not address, any other term or aspect of the Arrangement Agreement or the transaction or any term or aspect of any other agreement or instrument contemplated by the Arrangement Agreement or entered into in connection with the transaction, including, without limitation, the NC Purchase Agreement, or the fairness of the transactions contemplated thereby, including, without limitation, the North Carolina transaction. Morgan Stanley expressed no opinion as to the relative fairness of any portion of the consideration to be paid by Atlantic Power for the CPILP units and the Class A and Class B shares in the capital of CPI Investments. Morgan Stanley expressed no opinion with respect to the fairness of the amount or nature of the compensation to any of the officers, directors or employees of CPILP or CPI Investments, or any class of such persons, relative to the consideration to be paid to the holders of the CPILP units and the Class A and Class B shares in the capital of CPI Investments in the transaction. Morgan Stanley did not make any independent valuation or appraisal of the assets or liabilities of CPILP, CPI Investments or Atlantic Power, nor was Morgan Stanley furnished with any such valuations or appraisals. Morgan Stanley's opinion was necessarily based on financial, economic, market and other conditions as in effect on, and the information made available to it as of, June 19, 2011. Events occurring after June 19, 2011 may affect Morgan Stanley's opinion and the assumptions used in preparing it, and Morgan Stanley did not assume any obligation to update, revise or reaffirm its opinion.

        The following is a summary of the material financial analyses performed by Morgan Stanley in connection with its oral opinion and the preparation of its written opinion, dated as of June 19, 2011. Although each analysis was provided to the Atlantic Power board of directors, in connection with arriving at its opinion, Morgan Stanley considered all of its analysis as a whole and did not attribute any particular weight to any analysis described below. Some of these summaries include information in tabular format. In order to understand fully the financial analyses used by Morgan Stanley, the tables

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must be read together with the text of each summary. The tables alone do not constitute a complete description of the analyses.

        Historical Trading and Exchange Ratio Review.    Morgan Stanley reviewed the ranges of closing prices of Atlantic Power common shares and CPILP units for various periods ending on June 17, 2011. Morgan Stanley noted that for the 52-week period ending June 17, 2011 the ranges of closing prices per share for Atlantic Power common shares and CPILP units were C$12.11 to C$15.50 and C$15.90 to C$21.22, respectively. Morgan Stanley also calculated the average trading ratio of the price of CPILP units to the price of Atlantic Power common shares over the following periods:

Period Ending June 17, 2011
  Average
Historical
Trading Ratio
 

June 17, 2011

    1.25 x

1 Week Prior

    1.26 x

1 Month Prior

    1.29 x

3 Months Prior

    1.33 x

6 Months Prior

    1.29 x

1 Year Prior

    1.30 x

        Morgan Stanley noted that the exchange ratio pursuant to the Arrangement Agreement is 1.3 shares of Atlantic Power common shares for each CPILP unit, and that the implied offer value per CPILP unit as of June 17, 2011 was C$19.42, based on the closing price of Atlantic Power common shares on June 17, 2011 of $14.96.

        Equity Research Analysts' Price Targets.    Morgan Stanley reviewed the most recent equity research analysts' per-share target prices for Atlantic Power common shares and CPILP units, respectively. These targets reflect each analyst's estimate of the future public market trading price for Atlantic Power common shares and CPILP units. Target prices for CPILP units ranged from C$16.50 to C$20.00, compared with the implied offer value per unit of C$19.42 as of June 17, 2011. Target prices for Atlantic Power common shares ranged from C$12.00 to C$15.00, compared with the closing price of Atlantic Power common shares of $14.96 as of June 17, 2011.

        The public market trading price targets published by equity research analysts do not necessarily reflect current market trading prices for Atlantic Power common shares or CPILP units and these estimates are subject to uncertainties, including the future financial performance of Atlantic Power and CPILP and future financial market conditions.

        Selected Companies Analysis.    Morgan Stanley reviewed and compared certain publicly available and internal financial information, ratios and publicly available market multiples relating to Atlantic Power and CPILP, respectively, to corresponding financial data for publicly-traded companies that shared characteristics with Atlantic Power and CPILP to derive an implied per share equity reference range for Atlantic Power and CPILP.

        The companies included in the selected companies analysis were:

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        Morgan Stanley then reviewed both publicly available and internal financial information for each of Atlantic Power and CPILP to compare financial information and multiples of market value of the companies included in the selected companies analysis to the following metrics for Atlantic Power and CPILP:

        The following table reflects the results of this analysis, as well as the multiples for Atlantic Power and CPILP based on the median statistics of EBITDA for these companies obtained from I/B/E/S, a data service that monitors and publishes a compilation of earnings estimates produced by selected research analysts on companies of interest to investors:

 
  Aggregate Value to EBITDA
 
  2011E   2012E

Representative range derived for Atlantic Power from selected companies

  11.0x - 13.0x   9.0x - 11.0x

Atlantic Power multiples (I/B/E/S)

  13.9x   13.0x

Representative range derived for CPILP from selected companies

  11.0x - 13.0x   9.0x - 11.0x

CPILP multiples (I/B/E/S)

  10.3x   10.0x

        Applying representative ranges of multiples that were derived from the selected companies analysis, Morgan Stanley calculated an implied per share equity reference range for Atlantic Power common shares and CPILP units with respect to the following metrics:

        Based on this analysis, Morgan Stanley derived an implied per share equity reference range for Atlantic Power common shares of C$12.26 to C$18.85 and an implied per share equity reference range for CPILP units of C$14.94 to C$28.33.

        Morgan Stanley noted that the implied offer value per CPILP unit as of June 17, 2011 was C$19.42, based on the closing price of Atlantic Power common shares on June 17, 2011 of $14.96.

        Atlantic Power management prepared two financial forecasts for CPILP, referred to as Case 1 and Case 2, which incorporated the results of due diligence that were performed by Atlantic Power on CPILP. Morgan Stanley also performed an EBITDA multiple analysis on Atlantic Power common shares in the combined company post-transaction, using projections for both Atlantic Power and CPILP provided by the management of Atlantic Power, which incorporated synergies related to the elimination of certain public company costs identified by Atlantic Power management. Applying representative ranges of multiples that were derived from the selected companies analysis, Morgan Stanley calculated a range of implied per share equity reference ranges for Atlantic Power common shares in the combined company post-transaction with respect to the following metrics:

        Based on this analysis, Morgan Stanley derived an implied per share equity reference range for Atlantic Power common shares in the combined company post-transaction of C$10.83 to C$20.89.

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        No company utilized in the selected companies analysis is identical to Atlantic Power or CPILP. Accordingly, an analysis of the results of the foregoing necessarily involves complex considerations and judgments concerning differences in financial and operating characteristics of Atlantic Power and CPILP and other factors that could affect the public trading value of the companies to which they are being compared. In evaluating the selected companies, Morgan Stanley made judgments and assumptions with regard to industry performance, general business, economic, market and financial conditions and other matters, many of which are beyond the control of Atlantic Power and CPILP, such as the impact of competition on the businesses of Atlantic Power or CPILP and the industry generally, industry growth and the absence of any adverse material change in the financial conditions and prospects of Atlantic Power or CPILP or the industry or in the financial markets in general. Mathematical analysis, such as determining the mean, median or average, is not in itself a meaningful method of using selected company data.

        Discounted Cash Flow Analyses.    Morgan Stanley performed a discounted cash flow analysis (DCF) on Atlantic Power and CPILP using projections provided by Atlantic Power management. A discounted cash flow analysis is designed to provide insight into the value of a company as a function of its future cash flows and terminal value. Morgan Stanley's DCF analysis of Atlantic Power and CPILP involved discounting to a present value the projected levered after tax free cash flows from January 1, 2012 until December 31, 2024 for each of Atlantic Power and CPILP, plus terminal values determined as at December 31, 2024, utilizing a range of costs of equity which were chosen by Morgan Stanley based upon an analysis of market discount rates applicable to selected companies.

        Atlantic Power.    Morgan Stanley calculated indications of net present value of levered after tax free cash flows for Atlantic Power for the years 2012 through 2024 using discount rates ranging from 8.0% to 9.0%, reflecting estimates of Atlantic Power's cost of equity. Morgan Stanley then calculated an implied terminal value for Atlantic Power by applying a perpetual growth rate of 0% to an illustrative terminal year levered after tax free cash flow, which is the cash flow assumed to continue into perpetuity following the initial projection period that ends in the year 2024. This illustrative terminal value was then discounted to calculate indications of present value using an illustrative terminal discount rate ranging from 8.0% to 9.0%. From this analysis, Morgan Stanley calculated an implied per share equity reference range for Atlantic Power common shares of C$8.24 to C$8.93.

        CPILP.    Morgan Stanley calculated indications of net present value of levered after tax free cash flows for CPILP for the years 2012 through 2024 using discount rates ranging from 8.0% to 9.0%, reflecting estimates of CPILP's cost of equity. Morgan Stanley then calculated an implied terminal value for CPILP by applying a perpetual growth rate of 0% to an illustrative terminal year levered after tax free cash flow, which is the cash flow assumed to continue into perpetuity following the initial projection period that ends in the year 2024. This illustrative terminal value was then discounted to calculate indications of present value using an illustrative terminal discount rate ranging from 8.0% to 9.0%. Morgan Stanley performed these analyses utilizing Cases 1 and 2, the two financial forecasts prepared for CPILP by Atlantic Power management. From this analysis, Morgan Stanley calculated an implied per share equity reference range for CPILP units of C$14.52 to C$18.85.

        Pro Forma Analysis.    Morgan Stanley calculated indications of net present value of levered after tax free cash flows for Atlantic Power on a pro forma basis for the transaction for the years 2012 through 2024 using discount rates ranging from 8.0% to 9.0%, reflecting estimates of Atlantic Power's pro forma cost of equity. Morgan Stanley then calculated an implied terminal value for Atlantic Power on a pro forma basis by applying a perpetual growth rate of 0% to an illustrative terminal year levered after tax free cash flow, which is the cash flow assumed to continue into perpetuity following the initial projection period that ends in the year 2024. This illustrative terminal value was then discounted to calculate indications of present value using an illustrative terminal discount rate ranging from 8.0% to 9.0%. Morgan Stanley performed these pro forma analyses utilizing Cases 1 and 2, the two financial

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forecasts prepared for CPILP by Atlantic Power management. Included in this pro forma analysis were synergies related to the elimination of certain public company costs identified by Atlantic Power management. From this analysis, Morgan Stanley calculated an implied per share equity reference range for Atlantic Power common shares pro forma for the transaction of C$9.51 to C$11.69.

        Morgan Stanley noted that the implied offer value per CPILP unit as of June 17, 2011 was C$19.42, based on the closing price of Atlantic Power common shares on June 17, 2011 of $14.96.

        Distributable Cash Flow Accretion Analysis.    Morgan Stanley performed distributable cash flow accretion analysis, which compares projected cash flows available for distribution to common shareholders of Atlantic Power on a standalone basis and pro forma for the transaction, using forecasts prepared by Atlantic Power management. For purposes of this analysis, cash flow available for distribution is cash from operations less maintenance capital expenditures and mandatory debt principal or amortization payments.

Distributable Cash Per Share
  2012 - 2016 Average

Atlantic Power Standalone

  C$0.96

Pro Forma—Atlantic Power Management Case 1

  C$1.23

Pro Forma—Atlantic Power Management Case 2

  C$1.29

        Analysis of Selected Precedent Transactions.    Morgan Stanley also performed an analysis of selected precedent transactions, which attempted to provide an implied value for CPILP by comparing it to other companies involved in business combinations. Using publicly available information, Morgan Stanley considered the following set of transactions:

Announcement Date
  Acquiror   Target
May 2010   Boralex Inc.   Boralex Power Income Fund

February 2010

 

Innergex Power Income Fund

 

Innergex Renewable Energy Inc.

April 2009

 

Northland Power Income Fund

 

Northland Power Inc.

April 2008

 

FPL Energy, LLC

 

Creststreet Power & Income Fund LP

October 2007

 

Cheung Kong Infrastructure Holdings Ltd.

 

TransAlta Power, LP

June 2007

 

Fort Chicago Energy Partners LP

 

Countryside Power Income Fund

April 2007

 

Macquarie Power & Infrastructure Income Fund

 

Clean Power Income Fund

January 2007

 

Harbinger Capital Partners

 

Calpine Power Income Fund

May 2005

 

EPCOR Utilities Inc.

 

TransCanada Power L.P. (30.6% interest of public units and control of the GP)

        Morgan Stanley compared certain financial and market statistics of the selected precedent transactions. Based on an assessment of the selected precedent transactions, Morgan Stanley applied a representative range of multiples that were derived from the selected precedent transaction analysis and calculated an implied per share equity reference range for CPILP units with respect to aggregate value to 2011 estimated EBITDA.

        Based on this analysis, Morgan Stanley derived an implied per share equity reference range for CPILP units of C$14.30 to C$21.32.

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        Morgan Stanley noted that the implied offer value per CPILP unit as of June 17, 2011 was C$19.42, based on the closing price of Atlantic Power common shares on June 17, 2011 of $14.96.

        No company or transaction utilized as a comparison in the analysis of selected precedent transactions is identical to CPILP, Atlantic Power, or the transaction in business mix, timing and size. Accordingly, an analysis of the results of the foregoing necessarily involves complex considerations and judgments concerning differences in financial and operating characteristics of CPILP and Atlantic Power and other factors that would affect the value of the companies to which they are being compared. In evaluating the precedent transactions, Morgan Stanley made judgments and assumptions with regard to industry performance, global business, economic, market and financial conditions and other matters, many of which are beyond the control of CPILP and Atlantic Power, such as the impact of competition on CPILP and Atlantic Power and the industry generally, industry growth and the absence of any adverse material change in the financial conditions and prospects of CPILP, Atlantic Power, or the industry or the financial markets in general. Mathematical analysis, such as determining the mean or median, is not in itself a meaningful method of using precedent transactions data.

        In connection with the review of the transaction by Atlantic Power's board of directors, Morgan Stanley performed a variety of financial and comparative analyses for purposes of rendering its opinion. The preparation of a fairness opinion is a complex process and is not susceptible to partial analysis or summary description. In arriving at its opinion, Morgan Stanley considered the results of all of its analyses as a whole and did not attribute any particular weight to any analysis or factor considered. Furthermore, Morgan Stanley believes that the summary provided and the analyses described above must be considered as a whole and that selecting any portion of the analyses, without considering all of them, would create an incomplete view of the process underlying Morgan Stanley's analyses and opinion. In addition, Morgan Stanley may have given various analyses and factors more or less weight than other analyses and factors, and may have deemed various assumptions more or less probable than other assumptions. As a result, the ranges of valuations resulting from any particular analysis or combination of analyses described above should not be taken to be the view of Morgan Stanley with respect to the actual value of CPILP units or Atlantic Power common shares.

        In performing its analyses, Morgan Stanley made numerous assumptions with respect to industry performance, general business and economic conditions and other matters, many of which are beyond the control of CPILP or Atlantic Power. Many of these assumptions are beyond the control of CPILP and Atlantic Power. Any estimates contained in Morgan Stanley's analyses are not necessarily indicative of future results or actual values, which may be significantly more or less favorable than those suggested by the estimates. The analyses were performed solely as part of Morgan Stanley's analysis of the fairness from a financial point of view of the consideration to be paid by Atlantic Power pursuant to the Arrangement Agreement and were conducted in connection with the delivery of Morgan Stanley's opinion dated June 19, 2011 to the Atlantic Power board of directors. The analyses do not purport to be appraisals or to reflect the prices at which CPILP units or Atlantic Power common shares might actually trade. The consideration under the Arrangement Agreement and other terms of the Arrangement Agreement were determined through arm's length negotiations between CPILP and Atlantic Power and approved by the Atlantic Power board of directors. Morgan Stanley provided advice to Atlantic Power during these negotiations, but did not, however, recommend any specific purchase price or transaction consideration to Atlantic Power, or that any specific purchase price or transaction consideration constituted the only appropriate purchase price or transaction consideration for the transaction. The opinion of Morgan Stanley was one of a number of factors taken into consideration by Atlantic Power's board of directors in making its decision to approve the Arrangement Agreement and the transactions contemplated by the Arrangement Agreement. Consequently, Morgan Stanley's analyses described above should not be viewed as determinative of the opinion of Atlantic Power's

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board of directors with respect to the value of CPILP or Atlantic Power, or the consideration, or of whether the Atlantic Power board of directors would have been willing to agree to a different purchase price or transaction consideration. See the section entitled "The Arrangement Agreement and Plan of Arrangement—Atlantic Power's Reasons for the Arrangement Agreement; Recommendations of Atlantic Power's Board of Directors" beginning on page 55. Morgan Stanley's opinion was approved by a committee of Morgan Stanley investment banking and other professionals in accordance with its customary practice.

        Morgan Stanley, as part of its investment banking businesses, is continually engaged in the valuation of businesses and their securities in connection with mergers and acquisitions, negotiated underwritings, competitive biddings, secondary distributions of listed and unlisted securities, private placements and valuations for estate, corporate and other purposes. Atlantic Power selected Morgan Stanley as its financial advisor based upon the firm's qualifications, experience and expertise and because it is an internationally recognized investment banking firm with substantial experience in transactions similar to the transaction. In the ordinary course of its trading and brokerage activities, Morgan Stanley and its affiliates may at any time hold long or short positions, trade or otherwise effect transactions, for their own accounts or for the accounts of customers, in the equity or debt securities or senior loans of CPILP or Atlantic Power or any currency or commodity related to CPILP or Atlantic Power.

        Pursuant to the terms of its engagement, Atlantic Power has agreed to pay Morgan Stanley a fee of $1,000,000, which became payable upon announcement of the execution of the Arrangement Agreement and an additional fee of $4,000,000 that is payable upon consummation of the Plan of Arrangement. A portion of this fee is creditable against any financing fees that Morgan Stanley may receive in connection with the proposed transaction. Atlantic Power has also agreed to reimburse Morgan Stanley for its fees and expenses incurred in performing its services. In addition, Atlantic Power has agreed to indemnify Morgan Stanley and its affiliates, their respective directors, officers, agents and employees and each person, if any, controlling Morgan Stanley or any of its affiliates against certain liabilities and expenses, including certain liabilities under the federal securities laws, related to or arising out of Morgan Stanley's engagement and any related transactions.

        In addition, Morgan Stanley (jointly with TD Securities) has committed to provide a $625 million senior secured credit facility to Atlantic Power that can be utilized to fund the cash consideration required under the Plan of Arrangement and related fees and expenses, for which Morgan Stanley will receive customary compensation. Furthermore, Atlantic Power has agreed to retain Morgan Stanley and TD Securities to jointly lead any debt or equity offering related to the proposed transaction, for which Morgan Stanley will receive customary compensation.

Interests of Atlantic Power Directors and Officers in the Plan of Arrangement

        No current Atlantic Power directors or officers own CPILP units. Current Atlantic Power directors and officers will continue to hold their positions at the Combined Company after the Plan of Arrangement.

Certain Atlantic Power Prospective Financial Information

        Atlantic Power does not as a matter of course make public long-term forecasts as to future performance or other prospective financial information beyond the current fiscal year, and Atlantic Power is especially wary of making forecasts or projections for extended periods due to the unpredictability of the underlying assumptions and estimates. However, as part of the due diligence review of Atlantic Power in connection with the Arrangement Agreement, Atlantic Power's management prepared and provided to CPILP, as well as to TD Securities, Morgan Stanley, CIBC and Greenhill in connection with their respective evaluation of the fairness of the Arrangement Agreement

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consideration, non-public, internal financial forecasts regarding Atlantic Power's projected future operations for the 2011 through 2015 fiscal years. Atlantic Power has included below a summary of these forecasts for the purpose of providing shareholders and investors access to certain non-public information that was furnished to third parties and such information may not be appropriate for other purposes. These forecasts were also considered by the Atlantic Power board of directors for purposes of evaluating the Plan of Arrangement. The Atlantic Power board of directors also considered non-public, financial forecasts prepared by CPILP regarding CPILP's anticipated future operations for the 2011 through 2015 fiscal years for purposes of evaluating CPILP and the Plan of Arrangement. See "The Arrangement Agreement and Plan of Arrangement—Certain CPILP Prospective Financial Information" beginning on page 83 for more information about the forecasts prepared by CPILP.

        The Atlantic Power internal financial forecasts are not guidance and were not prepared with a view toward public disclosure, nor were they prepared with a view toward compliance with published guidelines of the SEC, the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of financial forecasts, the guidelines established by the Canadian Institute of Chartered Accountants Handbook, rules relating to future oriented financial information under Canadian securities laws or generally accepted accounting principles in the United States or Canada. KPMG LLP has not examined, compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, KPMG LLP does not express an opinion or any other form of assurance with respect thereto. The KPMG LLP reports incorporated by reference in this joint proxy statement relate only to Atlantic Power's historical financial information. They do not extend to the prospective financial information and should not be read to do so. The summary of these internal financial forecasts included below is not being included to influence your decision whether to vote for the Arrangement and the transactions contemplated in connection with the Arrangement, but because these internal financial forecasts were provided by Atlantic Power to CPILP and TD Securities, Morgan Stanley, CIBC and Greenhill.

        The inclusion of a summary of these internal financial forecasts in this joint proxy statement should not be regarded as an indication that any of Atlantic Power, CPILP or their respective affiliates, advisors or representatives considered these internal financial forecasts to be predictive of actual future events, and these internal financial forecasts should not be relied upon as such nor should the information contained in these internal financial forecasts be considered appropriate for purposes of making investment decisions in relation to Atlantic Power securities or for any other purposes. None of Atlantic Power, CPILP or their respective affiliates, advisors, officers, directors, partners or representatives can give you any assurance that actual results will not differ materially from these internal financial forecasts, and none of them undertakes any obligation to update or otherwise revise or reconcile these internal financial forecasts to reflect circumstances existing after the date these internal financial forecasts were generated or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying these forecasts are shown to be in error. Since the forecasts cover multiple years, such information by its nature becomes less meaningful and predictive with each successive year. Atlantic Power does not intend to make publicly available any update or other revision to these internal financial forecasts. None of Atlantic Power or its affiliates, advisors, officers, directors, partners or representatives has made or makes any representation to any shareholder or other person regarding Atlantic Power's ultimate performance compared to the information contained in these internal financial forecasts or that the forecasted results will be achieved. Atlantic Power has made no representation to CPILP, in the Arrangement Agreement or otherwise, concerning these internal financial forecasts. The below forecasts do not give effect to the Plan of Arrangement.

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Atlantic Power urges all shareholders to review Atlantic Power's most recent SEC filings for a description of Atlantic Power's reported financial results.

 
  Fiscal Year  
 
  2011   2012   2013   2014   2015  
 
  (US$ in millions)
 

EBITDA

  $ 139.7   $ 154.0   $ 158.8   $ 116.7   $ 127.4  

Distributable Cash Flow

  $ 62.4   $ 82.1   $ 76.1   $ 42.5   $ 56.9  

        Atlantic Power's internal financial forecasts above reflect numerous judgments, estimates and assumptions with respect to industry performance, general business, economic, regulatory, market and financial conditions and other future events, as well as matters specific to Atlantic Power's business all of which are difficult to predict and many of which are beyond control. Atlantic Power's internal financial forecasts are subjective in many respects and thus are susceptible to multiple interpretations and periodic revisions based on actual experience and business developments. As such, internal financial forecasts constitute forward-looking information and are subject to risks and uncertainties that could cause actual results to differ materially from the results forecasted in such projections, including the various risks described under the heading "Risk Factors" in this joint proxy statement and in Atlantic Power's Annual Report on Form 10-K for the year ended December 31, 2010, as updated by Atlantic Power's subsequent Quarterly Reports on Form 10-Q, all of which are filed with the SEC and/or incorporated by reference into this joint proxy statement. See also "Cautionary Note Regarding Forward-Looking Statements" beginning on page 30 of this joint proxy statement. There can be no assurance that the forecasted results will be realized or that actual results will not be significantly higher or lower than forecasted. Atlantic Power's internal financial forecasts cannot be considered a reliable predictor of future results and should not be relied upon as such. Atlantic Power's internal financial forecasts cover multiple years and such information by its nature becomes less reliable with each successive year.

        ATLANTIC POWER DOES NOT INTEND TO UPDATE OR OTHERWISE REVISE THE ABOVE INFORMATION TO REFLECT CIRCUMSTANCES EXISTING AFTER THE DATE WHEN MADE OR TO REFLECT THE OCCURRENCE OF FUTURE EVENTS, EVEN IN THE EVENT THAT ANY OR ALL OF THE ASSUMPTIONS UNDERLYING SUCH INFORMATION ARE NO LONGER APPROPRIATE, EXCEPT AS MAY BE REQUIRED BY APPLICABLE LAW.

CPILP's Reasons for the Plan of Arrangement; Recommendations of the Board of Directors of CPILP's General Partner

        At a meeting held on June 19, 2011, after considering, among other things, the oral opinions of CIBC and Greenhill, subsequently confirmed in writing, the full text of which are attached as Annexes D and E, respectively, of this joint proxy statement, the members of the board of directors of the General Partner entitled to vote, being the independent directors, determined unanimously that the Arrangement is in the best interests of CPILP and is fair to the CPILP unitholders and resolved unanimously to recommend to the CPILP unitholders that they vote in favor of the Arrangement. The members of the board of directors of the General Partner entitled to vote also unanimously approved the Arrangement and the execution and performance of the Arrangement Agreement. Accordingly, the board of directors of the General Partner unanimously recommends that the CPILP unitholders vote "FOR" the approval of the Arrangement Resolution.

        In considering the proposed business combination with Atlantic Power and in making its determination that the Arrangement is advisable and in the best interests of CPILP and its unitholders, the board of directors of the General Partner consulted with its management and financial, legal and other advisors, and considered a variety of factors weighing in favor of or relevant to the Plan of Arrangement, including the factors discussed below.

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        Strategic Benefits of the Plan of Arrangement.    The board of directors of the General Partner believes that the combination of Atlantic Power and CPILP should result in significant strategic benefits to the Combined Company, which would benefit CPILP and its unitholders to the extent they receive Atlantic Power common shares of the Combined Company. These strategic benefits include the following:

        Financial Benefits of the Plan of Arrangement.    The board of directors of the General Partner believes that the combination of Atlantic Power and CPILP should result in significant financial benefits to CPILP's unitholders and the Combined Company. These financial benefits include the following:

        Other Factors Considered.    During the course of its deliberations relating to the Arrangement Agreement, the board of directors of the General Partner considered the following factors in addition to the benefits described above:

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        The board of directors of the General Partner weighed these factors against a number of uncertainties, risks and potentially negative factors relevant to the Arrangement Agreement, including:

        The board of directors of the General Partner concluded that the uncertainties, risks and potentially negative factors relevant to the Plan of Arrangement were outweighed by the potential benefits that it expected CPILP and CPILP unitholders would achieve as a result of the Plan of Arrangement.

        This discussion of the information and factors considered by the board of directors of the General Partner includes the principal positive and negative factors considered by the board of directors, but is not intended to be exhaustive and may not include all of the factors considered. The board of directors of the General Partner did not quantify or assign any relative or specific weights to the various factors that it considered in reaching its determination that the Arrangement Agreement and the Arrangement

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is in the best interests of CPILP and is fair to the CPILP unitholders . Rather, the board of directors of the General Partner viewed its position and recommendation as being based on the totality of the information presented to it and the factors it considered. In addition, individual members of the board of directors of the General Partner may have given differing weights to different factors. It should be noted that this explanation of the reasoning of the board of directors of the General Partner and certain information presented in this section is forward-looking in nature and, therefore, that information should be read in light of the factors discussed in the section entitled "Cautionary Note Regarding Forward-Looking Statements" in this joint proxy statement, beginning on page 30.

Opinions of CPILP's Financial Advisors

Opinion of CIBC World Markets Inc.

        CIBC rendered its opinion to the board of directors of the General Partner that, as of June 19, 2011 and based upon and subject to the assumptions, limitations and qualifications set forth therein, the consideration to be received by holders of CPILP units, pursuant to the Arrangement Agreement was fair from a financial point of view to such holders (other than Capital Power and its affiliates).

        The full text of the written opinion of CIBC, dated June 19, 2011, which sets forth assumptions made, procedures followed, matters considered and limitations on the review undertaken in connection with the opinion, is attached as Annex D to this joint proxy statement. CIBC provided its opinion for the information and assistance of the board of directors of CPILP's general partner in connection with its consideration of the Plan of Arrangement and was one of a number of factors taken into consideration by the board of directors of the General Partner in making its unanimous determination that the offer is in the best interests of CPILP and is fair to the unitholders and to recommend that CPILP unitholders vote in favor of the Arrangement. The CIBC opinion does not constitute a recommendation as to how any CPILP unitholder should vote with respect to the Plan of Arrangement or any other matter.

Opinion of Greenhill & Co. Canada Ltd.

        The board of directors of the General Partner retained Greenhill to act as a financial advisor to the board of directors of the General Partner in connection with the Plan of Arrangement and to render to the board of directors of the General Partner an opinion as to the fairness to the holders of CPILP units (other than the General Partner, CPI Investments and Atlantic Power) of the purchase price pursuant to the Arrangement Agreement to be paid to such holders. At the meeting of the board of directors of CPILP's general partner on June 19, 2011, Greenhill rendered its opinion to the board of directors of CPILP's general partner to the effect that, as of that date and based upon and subject to various limitations, qualifications and assumptions set forth in its written opinion, the purchase price pursuant to the Arrangement Agreement to be paid to the holders of CPILP units (other than the General Partner, CPI Investments and Atlantic Power), was fair, from a financial point of view, to such holders.

        The full text of the written opinion of Greenhill, dated as of June 19, 2011, is attached as Annex E to this joint proxy statement. Greenhill's opinion sets forth, among other things, the assumptions made, procedures followed, matters considered and limitations and qualifications on the scope of the review undertaken by Greenhill in rendering its opinion. CPILP encourages its unitholders to read the opinion carefully and in its entirety. Greenhill's opinion was directed to the board of directors of CPILP's general partner and addresses only the fairness from a financial point of view of the purchase price to the CPILP unitholders (other than the General Partner, CPI Investments and Atlantic Power), as of the date of the opinion. It does not address any other aspects of the Plan of Arrangement and does not constitute a recommendation as to how any holder of CPILP unit should vote on the Arrangement or any matter related thereto.

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Interests of CPILP Directors and Officers in the Plan of Arrangement

        Certain of the directors and officers of the general partner of CPILP are also officers and/or directors of Capital Power and its affiliates and are not considered to be independent of CPILP within the meaning of applicable Canadian securities laws. Capital Power and its affiliates have interests in the Plan of Arrangement and certain other transactions to be completed in connection with the Plan of Arrangement that are different from, or in addition to, the interests of the other CPILP unitholders. See "Canadian Securities Law Matters" beginning on page 85.

        The board of directors of the General Partner was aware of and considered these interests, among other matters, in evaluating the Plan of Arrangement, and in recommending that CPILP unitholders vote in favor of the Arrangement Resolution. The members of the board of directors of the General Partner who are officers and/or directors of Capital Power and its affiliates did not participate in the vote to approve the Arrangement, as a result of the potential conflict of interest presented by their positions with Capital Power and its affiliates.

        The following table indicates, as of September 7, 2011, the number of CPILP units beneficially owned, directly or indirectly, or over which control or direction is exercised, by: (i) each director and officer of CPILP; (ii) each associate or affiliate of an insider of CPILP; (iii) each associate or affiliate of CPILP; (iv) each insider of CPILP (other than a director or officer of CPILP; and (v) each person acting jointly or in concert with CPILP, and the maximum amount of potential cash consideration payable to each pursuant to the Plan of Arrangement:

Name
  Position with CPILP   CPILP
Units
  Maximum
Amount of
Potential Cash
Consideration
 

Graham L. Brown

  Director         n/a  

Brian A. Felesky

  Director (Independent)     5,640   $ 109,416  

Allen R. Hagerman

  Director (Independent)     17,702   $ 343,419  

Francois L. Poirier

  Director (Independent)     3,100   $ 60,140  

Brian T. Vaasjo

  Chairman and Director     7,400   $ 143,560  

Rodney D. Wimer

  Director (Independent)         n/a  

James Oosterbaan

  Director         n/a  

Stuart A. Lee

  Director and President     3,536   $ 68,598  

B. Kathryn Chisholm

  General Counsel and Corporate Secretary     915   $ 17,751  

Peter D. Johanson

  Controller     400   $ 7,760  

Leah M. Fitzgerald

  Assistant Corporate Secretary         n/a  

Anthony Scozzafava

  Chief Financial Officer     2,050   $ 39,770  

Yale Loh

  Vice President, Treasurer         n/a  

Capital Power Corporation(1)

  Unitholder     16,513,504   $ 320,361,978  

(1)
Capital Power indirectly owns 49% of the voting interests and all of the economic interests in CPI Investments. EPCOR owns the remaining 51% voting interest in CPI Investments. CPI Investments owns 16,513,504 CPILP units. Under the Plan of Arrangement, Atlantic Power will acquire all of the outstanding shares of CPI Investments on effectively the same basis as the acquisition of CPILP units under the Plan of Arrangement.

        The current directors and officers of the General Partner will resign their positions in connection with the Plan of Arrangement.

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Certain CPILP Prospective Financial Information

        CPILP does not as a matter of course make public long-term forecasts as to future performance or other prospective financial information beyond the current fiscal year, and CPILP is especially wary of making forecasts or projections for extended periods due to the unpredictability of the underlying assumptions and estimates. However, as part of the due diligence review of CPILP in connection with the Plan of Arrangement, CPILP's management prepared and provided to Atlantic Power, as well as to TD Securities, Morgan Stanley, CIBC and Greenhill in connection with their respective evaluation of the fairness of the Arrangement Agreement consideration, non-public, internal financial forecasts regarding CPILP's projected future operations for the 2011 through 2015 fiscal years. CPILP has included below a summary of these forecasts for the purpose of providing unitholders and investors access to certain non-public information that was furnished to third parties and such information may not be appropriate for other purposes. These forecasts were also considered by the CPILP's general partner's board of directors for purposes of evaluating the Plan of Arrangement. The CPILP's general partner's board of directors also considered non-public, financial forecasts prepared by Atlantic Power regarding Atlantic Power's anticipated future operations for the 2011 through 2015 fiscal years for purposes of evaluating Atlantic Power and the Plan of Arrangement. See "The Arrangement Agreement and Plan of Arrangement—Certain Atlantic Power Prospective Financial Information" beginning on page 75 for more information about the forecasts prepared by Atlantic Power.

        The CPILP internal financial forecasts are not guidance and were not prepared with a view toward public disclosure, nor were they prepared with a view toward compliance with published guidelines of the SEC, the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of financial forecasts, the guidelines established by the Canadian Institute of Chartered Accountants Handbook, rules relating to future oriented financial information under Canadian securities laws or generally accepted accounting principles in the United States or Canada. KPMG has not examined, compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, KPMG does not express an opinion or any other form of assurance with respect thereto. The KPMG reports incorporated by reference in this joint proxy statement relate to CPILP's historical financial information. They do not extend to the prospective financial information and should not be read to do so. The summary of these internal financial forecasts included below is not being included to influence your decision whether to vote for the Arrangement and the transactions contemplated in connection with the Arrangement, but because these internal financial forecasts were provided by CPILP to Atlantic Power and TD Securities, Morgan Stanley, CIBC and Greenhill.

        The inclusion of a summary of these internal financial forecasts in this joint proxy statement should not be regarded as an indication that any of CPILP, Atlantic Power or their respective affiliates, advisors or representatives considered these internal financial forecasts to be predictive of actual future events, and these internal financial forecasts should not be relied upon as such nor should the information contained in these internal financial forecasts be considered appropriate for purposes of making investments decisions in relation to CPILP units or for any other purposes. None of Atlantic Power, CPILP or their respective affiliates, advisors, officers, directors, partners or representatives can give you any assurance that actual results will not differ materially from these internal financial forecasts, and none of them undertakes any obligation to update or otherwise revise or reconcile these internal financial forecasts to reflect circumstances existing after the date these internal financial forecasts were generated or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying these forecasts are shown to be in error. Since the forecasts cover multiple years, such information by its nature becomes less meaningful and predictive with each successive year. CPILP does not intend to make publicly available any update or other revision to these internal financial forecasts. None of CPILP or its affiliates, advisors, officers, directors, partners or representatives has made or makes any representation to any shareholder or other person regarding

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CPILP's ultimate performance compared to the information contained in these internal financial forecasts or that the forecasted results will be achieved. CPILP has made no representation to Atlantic Power, in the Arrangement Agreement or otherwise, concerning these internal financial forecasts. The below forecasts do not give effect to the Plan of Arrangement. CPILP urges all unitholders to review CPILP's financial statements included in CPILP's Audited Consolidated Financial Statements as at and for the Years Ended December 31, 2010, 2009 and 2008 and Unaudited Condensed Interim Financial Statements as at and for the Six Months Ended June 30, 2011, which are delivered with, and/or incorporated by reference into, this joint proxy statement.

 
  Fiscal Year  
 
  2011   2012   2013   2014   2015  
 
  ($ in millions)
 

EBITDA

  $ 205.2   $ 215.2   $ 219.7   $ 219.7   $ 234.3  

Cash available for distribution

  $ 122.3   $ 136.3   $ 130.7   $ 135.3   $ 134.1  

        CPILP's internal financial forecasts above reflect numerous judgments, estimates and assumptions with respect to industry performance, general business, economic, regulatory, market and financial conditions and other future events, as well as matters specific to CPILP's business as set out in CPILP's "Forward Looking Statements" contained in CPILP's Management's Discussion and Analysis for the Year Ended December 31, 2010, which is delivered with, and/or incorporated by reference into this joint proxy statement. All of these assumptions and estimates are difficult to predict and many of which are beyond control. CPILP's internal financial forecasts are subjective in many respects and thus are susceptible to multiple interpretations and periodic revisions based on actual experience and business developments. As such, internal financial forecasts constitute forward-looking information and are subject to risks and uncertainties that could cause actual results to differ materially from the results forecasted in such projections, including the various risks and uncertainties described under the heading "Risk Factors" included in CPILP's Annual Information Form dated March 11, 2011 and under the heading "Business Risks" included in CPILP's Management's Discussion and Analysis for the Year Ended December 31, 2010, as well as the risk factors set forth elsewhere in this joint proxy statement and also under the heading "Cautionary Note Regarding Forward-Looking Statements" beginning on page 30 of this joint proxy statement and CPILP's "Forward-Looking Information" contained in CPILP's Management's Discussion and Analysis for the Year Ended December 31, 2010, which is delivered with, and/or incorporated by reference into, this joint proxy statement. There can be no assurance that the forecasted results will be realized or that actual results will not be significantly higher or lower than forecasted. CPILP's internal financial forecasts cannot be considered a reliable predictor of future results and should not be relied upon as such. CPILP's internal financial forecasts cover multiple years and such information by its nature becomes less reliable with each successive year.

        CPILP DOES NOT INTEND TO UPDATE OR OTHERWISE REVISE THE ABOVE INFORMATION TO REFLECT CIRCUMSTANCES EXISTING AFTER THE DATE WHEN MADE OR TO REFLECT THE OCCURRENCE OF FUTURE EVENTS, EVEN IN THE EVENT THAT ANY OR ALL OF THE ASSUMPTIONS UNDERLYING SUCH INFORMATION ARE NO LONGER APPROPRIATE, EXCEPT AS MAY BE REQUIRED BY APPLICABLE LAW.

Accounting Treatment of the Arrangement

        Atlantic Power will account for the acquisition using the acquisition method of accounting, as prescribed in Accounting Standards Codification 805, "Business Combinations," under US generally accepted accounting principles.

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Court Approval Required for the Plan of Arrangement

Interim Order

        On                , 2011, the Court of Queen's Bench of Alberta (the "Court") granted the Interim Order facilitating the calling of the CPILP special meeting and prescribing the conduct of the CPILP special meeting and other matters. The Interim Order is attached hereto as Annex H to this joint proxy statement.

Final Order

        The CBCA provides that an arrangement requires court approval. Subject to the terms of the Arrangement Agreement, and if the Arrangement Resolution is approved by CPILP unitholders at the CPILP special meeting in the manner required by the Interim Order, CPILP and the General Partner, as general partner of CPILP, will make an application to the Court for a final order (the "Final Order").

        The application for the Final Order approving the Arrangement is scheduled for                , 2011 at            (Calgary time), at Calgary, Alberta, or as soon thereafter as counsel may be heard in Calgary, Alberta. The notice of application in respect of the Final Order is attached hereto as Annex I. At the hearing, the Court will consider, among other things, the fairness and reasonableness of the terms of the Arrangement, including the fairness of the Arrangement to CPILP unitholders. At the hearing, any CPILP unitholder and any other interested party who wishes to participate or to be represented or to present evidence or argument may do so, subject to filing with the Court and serving upon CPILP and Atlantic Power a notice of intention to appear together with any evidence or materials which such party intends to present to the Court on or before            , 2011. Service of such notice will be effected by service upon the General Partner's legal counsel, Fraser Milner Casgrain LLP, Bankers Court, 15th Floor, 850-2nd Street SW, Calgary, Alberta T2P 0R8, Attention: Brian Foster with a copy to Atlantic Power's legal counsel, Goodmans LLP, 333 Bay Street, Suite 3400, Toronto, Ontario M5H 2S7, Attention: Tom Friedland and Jason Wadden.

        The Court has broad discretion under the CBCA when making orders with respect to the Arrangement and that the Court will consider, among other things, the fairness and reasonableness of the Arrangement, both from a substantive and a procedural point of view. The Court may approve the Arrangement, either as proposed or as amended, in any manner the Court may direct, subject to compliance with such terms and conditions, if any, as the Court thinks fit. Depending upon the nature of any required amendments, CPILP, the General Partner, CPI Investments and Atlantic Power may determine not to proceed with the Arrangement.

        If made, the Final Order will constitute the basis for an exemption, under Section 3(a)(10) of the Securities Act, from the registration requirements of the Securities Act with respect to the Plan of Arrangement and the Court will be so advised in advance.

Canadian Securities Law Matters

Ongoing Canadian Reporting Obligations

        CPILP is a reporting issuer (or the equivalent) in all of the provinces and territories of Canada. CPILP units currently trade on the TSX. After the Plan of Arrangement, Atlantic Power intends to delist the CPILP units from the TSX. The preferred shares of CPI Preferred Equity Ltd. will remain outstanding and listed on the TSX.

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Special Transaction Rules

        The Ontario and Quebec securities commissions have adopted Multilateral Instrument 61-101—Protection of Minority Security Holders in Special Transactions ("MI 61-101"), which governs transactions that raise the potential for conflicts of interest, including issuer bids, insider bids, related party transactions and business combinations.

        For the reasons set out in the following paragraph, the Plan of Arrangement will constitute a "business combination" under MI 61-101 and the Arrangement Resolution will require "minority approval" in accordance with MI 61-101. The Arrangement Resolution will have to be approved by a simple majority of the votes cast by the CPILP unitholders, excluding those votes required to be excluded pursuant to the minority approval provisions of MI 61-101, being the votes of "interested parties" and their related parties and joint actors, which include CPI Investments and the General Partner. This approval is in addition to the requirement that the Arrangement Resolution must be approved by not less than 662/3% of the votes cast by the unitholders of CPILP that vote in person or by proxy at the CPILP special meeting.

        As part of the Plan of Arrangement, an affiliate of Capital Power will acquire CPILP's Southport and Roxboro facilities in North Carolina. In addition, certain management and operations agreements between Capital Power and its subsidiaries and CPILP and its subsidiaries will be terminated and/or assigned in consideration for the payment by CPILP and its subsidiaries of C$10.0 million. See "Summary of the Arrangement Agreement—Summaries of Other Agreements Relating to the Arrangement—Management Agreements Termination Agreement and Management Agreement Assignment Agreement" beginning on page 106. Capital Power and its subsidiaries are "related parties" of CPILP within the meaning of MI 61-101 and the sale of the North Carolina facilities and the termination and/or assignment of the management and operations agreements would constitute "connected transactions" (collectively, the "Connected Transactions") within the meaning of MI 61-101. Accordingly, the Plan of Arrangement will constitute a "business combination" for CPILP under MI 61-101.

        As a result of the foregoing, the votes attaching to CPILP units beneficially owned, or over which control or direction is exercised, by CPI Investments and the General Partner, representing approximately 29.18% of the outstanding CPILP units, will be excluded in determining whether minority approval of the Arrangement Resolution has been obtained.

        The Plan of Arrangement is exempt from the formal valuation requirements of MI 61-101 for certain "business combinations" on the basis that at the time the Connected Transactions were agreed to, neither the fair market value of the subject matter of, nor the fair market value of the consideration for, the Connected Transactions, exceeded 25% of CPILP's market capitalization.

        The foregoing was reviewed by the independent directors of the General Partner in connection with their review and approval process for the Plan of Arrangement. See "The Arrangement Agreement and Plan of Arrangement—CPILP's Reasons for the Plan of Arrangement; Recommendations of the Board of Directors of CPILP's General Partner" beginning on page 77.

        To the knowledge of CPILP and Atlantic Power, there have been no prior valuations of CPILP or Atlantic Power, the CPILP units or the Atlantic Power common shares, or the material assets of CPILP or Atlantic Power in the 24 months prior to the date of this joint proxy statement.

Judicial Developments

        The Plan of Arrangement will be implemented pursuant to section 192 of the CBCA, which provides that, where it is not practicable for a corporation to effect a fundamental change in the nature of an arrangement under any other provisions of the CBCA, a corporation may apply to a court for an order approving the Plan of Arrangement proposed by such corporation. Pursuant to this section of the

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CBCA, such an application will be made by CPILP and the General Partner for approval of the Plan of Arrangement. See above under the heading "—Court Approval Required for the Plan of Arrangement." Although there have been a number of judicial decisions considering this section of the CBCA and applications to various arrangements, there have not been, to the knowledge of CPILP or Atlantic Power, any recent significant decisions which would apply in this instance. CPILP unitholders should consult their legal advisors with respect to the legal rights available to them in relation to the Plan of Arrangement.

Restrictions on Sales of Shares (Canada)

        The Atlantic Power common shares to be issued in exchange for CPILP units pursuant to the Plan of Arrangement will be issued in reliance upon exemptions from the prospectus requirements of securities legislation in each province and territory of Canada. Subject to customary restrictions applicable to distributions of shares that constitute "control distributions," Atlantic Power common shares issued pursuant to the Plan of Arrangement may be freely resold in each province and territory in Canada, subject to the conditions that: (i) no unusual effort has been made to prepare the market or create a demand for the common shares, (ii) no extraordinary commission or consideration is paid to a person or company in respect of the trade and (iii) if the selling securityholder is an insider or officer of Atlantic Power, the selling securityholder has no reasonable grounds to believe that Atlantic Power is in default of securities legislation.

United States Securities Law Matters

        The Atlantic Power common shares to be issued pursuant to the Plan of Arrangement will not be registered under the Securities Act or the securities laws of any state of the United States and will be issued in reliance upon the exemption from registration set forth in Section 3(a)(10) of the Securities Act. Section 3(a)(10) of the Securities Act exempts from registration the distribution of a security that is issued in exchange for outstanding securities where the terms and conditions of such issuance and exchange are approved, after a hearing on the fairness of such terms and conditions at which all persons to whom it is proposed to issue securities in such exchange have the right to appear, by a court or by a governmental authority expressly authorized by law to grant such approval. Accordingly, Atlantic Power expects the Final Order of the Court will, if granted, constitute a basis for the exemption from the registration requirements of the Securities Act with respect to the Atlantic Power common shares issued in connection with the Plan of Arrangement.

        The Atlantic Power common shares received by persons who will be an "affiliate" of Atlantic Power after the Plan of Arrangement will be subject to certain restrictions on resale in the U.S. imposed by the Securities Act. As defined in Rule 144 under the Securities Act, an "affiliate" of an issuer is a person that, directly or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with, the issuer and may include certain officers and directors of such issuer as well as principal shareholders of such issuer. Persons who are not affiliates after the Plan of Arrangement may resell the Atlantic Power common shares that they receive in connection with the Plan of Arrangement in the United States without restriction under the Securities Act.

        Persons who are affiliates of Atlantic Power after the Plan of Arrangement may not sell their Atlantic Power common shares that they receive in connection with the Plan of Arrangement in the absence of registration under the Securities Act, unless an exemption from registration is available, such as the exemptions contained in Rule 144 or Rule 904 of Regulation S under the Securities Act, as described below.

        Affiliates—Rule 144.    In general, under Rule 144, persons who are affiliates of Atlantic Power after the Plan of Arrangement will be entitled to sell in the United States, during any three-month period, a portion of the Atlantic Power common shares that they receive in connection with the Plan of

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Arrangement, provided that the sale meets certain requirements. The number of such securities sold during such period may not exceed the greater of one percent of the then-outstanding securities of such class or, if such securities are listed on a United States securities exchange, the average weekly trading volume of such securities during the four-week period preceding the date of sale. The seller also must have held the Atlantic Power common shares for at least one year. In addition, the sale is subject to specified restrictions on manner of sale, notice requirements, aggregation rules and the availability of current public information about Atlantic Power. Persons who are affiliates of Atlantic Power after the Plan of Arrangement will continue to be subject to the resale restrictions described in this paragraph for so long as they continue to be affiliates of Atlantic Power.

        Affiliates—Regulation S.    In general, under Regulation S, persons who are affiliates of Atlantic Power solely by virtue of their status as an officer or director of Atlantic Power may sell their Atlantic Power common shares outside the United States in an "offshore transaction" (which would include a sale through the TSX, if applicable) if neither the seller nor any person acting on its behalf engages in "directed selling efforts" in the United States. In the case of a sale of Atlantic Power common shares received in connection with the Plan of Arrangement by an officer or director who is an affiliate of Atlantic Power solely by virtue of holding such position, there is also a requirement that no selling commission, fee or other remuneration is paid in connection with such sale other than a usual and customary broker's commission. For purposes of Regulation S, "directed selling efforts" means "any activity undertaken for the purpose of, or that could reasonably be expected to have the effect of, conditioning the market in the United States for any of the securities being offered" in the sale transaction. Certain additional restrictions are applicable to a holder of Atlantic Power common shares received in connection with the Plan of Arrangement, who is an affiliate of Atlantic Power after the Plan of Arrangement other than by virtue of his or her status as an officer or director of Atlantic Power.

        This document does not cover any resales of shares of Atlantic Power's common shares received in the Plan of Arrangement by any person who may be deemed an affiliate of Atlantic Power following completion of the Plan of Arrangement.

Stock Exchange Approvals

        Atlantic Power common shares currently trade on the TSX and NYSE. Atlantic Power will also apply to list Atlantic Power common shares issuable under the Plan of Arrangement on the NYSE and the TSX, and it is a condition to the completion of the Plan of Arrangement that Atlantic Power shall have obtained approval for these listings.

Regulatory Approvals Required for the Plan of Arrangement and Other Regulatory Matters

        Atlantic Power and CPILP have agreed to use their reasonable best efforts to obtain all governmental and regulatory approvals required to complete the transactions contemplated by the Arrangement Agreement.

Investment Canada Act (Canada)

        Subject to certain limited exceptions, the direct acquisition of control of a Canadian business by a non-Canadian that exceeds a financial threshold prescribed under Part IV of the Investment Canada Act (a "Reviewable Transaction") cannot be implemented unless the transaction has been reviewed by the Minister responsible for the Investment Canada Act (the "Minister") and the Minister is satisfied or is deemed to be satisfied that the transaction is likely to be of net benefit to Canada (the "net benefit ruling"). Accordingly, in the case of a Reviewable Transaction, a non-Canadian purchaser must submit an application to the Minister (an "Application for Review") seeking approval of the Reviewable Transaction and cannot complete the transaction until it receives a net benefit ruling. The submission

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of the Application for Review triggers an initial review period of up to 45 days. If the Minister has not completed the review by that date, the Minister may unilaterally extend the review period for up to a further 30 days. If necessary, the Minister and the purchaser may agree to further extensions of the review period.

        In determining whether to issue a net benefit ruling, the Minister is required to consider, among other things, the Application for Review and any written undertakings offered by the purchaser to Her Majesty in right of Canada. The prescribed factors that the Minister must consider when determining whether to issue a net benefit ruling include, among other things, the effect of the investment on the economic activity in Canada (including the effect on employment, resource processing, utilization of Canadian products and services and exports), the participation by Canadians in the acquired business, the effect of the investment on productivity, industrial, efficiency, technological development, product innovation, product variety and competition in Canada, the compatibility of the investment with national and provincial industrial, economic and cultural policies, and the contribution of the investment to Canada's ability to compete in world markets.

        If, following his review during the initial review period or the extension(s) described above, the Minister is not satisfied or deemed to be satisfied that the Reviewable Transaction is likely to be of net benefit to Canada, the Minister is required to send a notice to that effect to the purchaser, advising the purchaser of its right to make further representations and submit (additional) undertakings within 30 days from the date of such notice or any further period that may be agreed to by the purchaser and the Minister.

        At any time, and in any event within a reasonable time after the expiry of the last-mentioned period for making representations and submitting undertakings described above, the Minister shall send a notice to the purchaser that either the Minister is satisfied that the investment is likely to be of net benefit to Canada (i.e., a net benefit ruling) or confirmation that the Minister is not satisfied that the investment is likely to be of net benefit to Canada. In the latter case, the Reviewable Transaction may not be implemented.

        The Plan of Arrangement is a Reviewable Transaction. An Application for Review under the Investment Canada Act was filed by Atlantic Power in due course.

Competition Act (Canada)

        Part IX of the Competition Act (Canada) (the "Competition Act") requires that, subject to certain limited exceptions, the Commissioner of Competition ("Commissioner") be notified of certain classes of transactions that exceed the thresholds set out in Sections 109 and 110 of the Competition Act ("Notifiable Transactions") by the parties to the transaction.

        The parties to a Notifiable Transaction cannot complete the transaction until they have submitted the information prescribed pursuant to subsection 114(1) of the Competition Act to the Commissioner and the applicable waiting period has expired or been terminated or waived by the Commissioner, provided that there is no order in effect prohibiting completion at the relevant time.

        Atlantic Power filed with the Commissioner a request for an advance ruling certificate, pursuant to subsection 102(1) of the Competition Act, or in the alternative a no-action letter and a waiver from merger notification on August 12, 2011. On August 26, 2011, the Commissioner issued a "no-action" letter and waiver from merger notification in respect of the Plan of Arrangement, providing that, as at such date, the Commissioner does not intend to challenge the transaction by making an application under Section 92 of the Competition Act. The "no-action" letter acknowledges that the Commissioner reserves the right to challenge the Plan of Arrangement up to one year after it has been substantially completed.

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HSR Act

        Under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act"), certain transactions may not be completed until each party has filed a Notification and Report Form with the Antitrust Division of the US Department of Justice (the "DOJ") and with the US Federal Trade Commission (the "FTC") and the HSR Act's waiting period has expired or early termination of the waiting period has been granted. The transactions contemplated by the Plan of Arrangement are subject to the HSR Act.

        Atlantic Power and CPILP filed the requisite Notification and Report Forms on August 12, 2011. The waiting period expired on August 26, 2011. The early termination of the waiting period does not bar the FTC or the DOJ from subsequently challenging the Plan of Arrangement.

        At any time before or after the Plan of Arrangement is completed, the DOJ, the FTC, or others (including states and private parties) could attempt to take action under the antitrust laws, including seeking to prevent the Plan of Arrangement, to rescind the Plan of Arrangement, or to conditionally approve the completion of the Plan of Arrangement upon the divestiture of assets of Atlantic Power and CPILP. There can be no assurance that a challenge to the transactions contemplated by the Plan of Arrangement on antitrust grounds will not be made or, if a challenge is made, that it would not be successful.

Federal Power Act

        Atlantic Power and CPILP each have public utility subsidiaries subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC"), under the Federal Power Act ("FPA"). Section 203 of the FPA provides that no holding company in a holding company system that includes a transmitting utility or an electric utility may purchase, acquire, merge or consolidate with a transmitting utility, an electric utility company or a holding company in a holding company system that includes a transmitting utility or electric utility company without prior FERC authorization. Further, Section 203 requires prior authorization from the FERC for certain transactions resulting in the direct or indirect change of control over a FERC jurisdictional public utility. Consequently, the FERC's approval of the Plan of Arrangement under Section 203 of the FPA is required.

        The FERC must authorize the Plan of Arrangement if it finds that the Plan of Arrangement is consistent with the public interest. The FERC has stated that, in analyzing a merger or transaction under Section 203 of the FPA, it will evaluate the impact of the Plan of Arrangement on:

        In addition, in accordance with the Energy Policy Act of 2005, the FERC also must find that the Plan of Arrangement will not result in the cross-subsidization by utilities of their non-utility affiliates or the improper encumbrance or pledge of utility assets. If such cross-subsidization or encumbrances were to occur as a result of the Plan of Arrangement, the FERC then must find that such cross-subsidization or encumbrances are consistent with the public interest.

        The FERC will review these factors to determine whether the Plan of Arrangement is consistent with the public interest. If the FERC finds that a transaction would adversely affect competition in wholesale electric power markets, rates for transmission or the wholesale sale of electric energy, or regulation, or that the transaction would result in cross-subsidies or improper encumbrances that are not consistent with the public interest, it may, pursuant to the FPA, impose upon the proposed transaction remedial conditions intended to mitigate such effects or it may decline to authorize the transaction. The FERC is required to rule on a completed Section 203 application not later than

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180 days from the date on which the completed application is filed. The FERC may, however, for good cause, issue an order extending the time for consideration of the Section 203 application by an additional 180 days. If the FERC does not issue an order within the statutory deadline, then the transaction is deemed to be approved. Atlantic Power and CPILP expect that the FERC will approve the Plan of Arrangement within the initial 180-day review period. However, there is no guarantee that the FERC will not extend the time period for its review or not impose conditions on its approval that are unacceptable to Atlantic Power or CPILP.

        Atlantic Power and CPILP and their respective public utility subsidiaries filed their application under Section 203 on July 25, 2011.

General

        In connection with obtaining the approval of all necessary governmental authorities to complete the Plan of Arrangement, including but not limited to the governmental authorities specified above, there can be no assurance that:

        Atlantic Power and CPILP cannot assure you that a regulatory challenge to the Plan of Arrangement will not be made or that, if a challenge is made, it will not prevail.

        In the event that a governmental approval imposes conditions on, or requires divestitures relating to, the operations or assets of Atlantic Power or CPILP, each party has agreed that the other party would not be required, or permitted without prior written consent, to take any actions with respect to such conditions or divestitures if such actions would, or would reasonably be expected to, result (after giving effect to any reasonably expected proceeds of any divestiture or sale of assets) in a Material Adverse Effect on the Combined Company. See "Summary of the Arrangement Agreement—Conditions Precedent to the Plan of Arrangement" on page 94.

Listing of Atlantic Power Shares

        Following the completion of the Plan of Arrangement, Atlantic Power intends to maintain its listings on the NYSE and TSX under the symbols "AT" and "ATP," respectively, and the preferred shares of CPI Preferred Equity Ltd. will remain outstanding and listed on the TSX.

Appraisal/Dissent Rights

        The holders of Atlantic Power common shares are not entitled to dissent rights in connection with the Share Issuance Resolution.

        The unitholders of CPILP are not entitled to dissent rights in connection with the Arrangement Resolution.

Litigation Related to the Plan of Arrangement

        None.

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Effect of the Plan of Arrangement on CPILP's Other Securities

CPI Preferred Equity Ltd.

        CPI Preferred Equity Ltd., a subsidiary of CPILP, is authorized to issue an unlimited number of preferred shares issuable in series, of which up to 5,750,000 Cumulative Redeemable Preferred Shares, Series 1 (the "Series 1 Shares"), 4,000,000 Cumulative Rate Reset Preferred Shares, Series 2 (the "Series 2 Shares") and 4,000,000 Cumulative Floating Rate Preferred Shares, Series 3 (the "Series 3 Shares") have been authorized for issuance.

        As of September 7, 2011, CPI Preferred Equity Ltd. has issued 5,000,000 Series 1 Shares, 4,000,000 Series 2 Shares and no Series 3 Shares. The Series 1 Shares trade on the TSX under the symbol CZP.PR.A and the Series 2 Shares trade on the TSX under the symbol CZP.PR.B. CPILP has agreed to fully and unconditionally guarantee the Series 1 Shares, Series 2 Shares and Series 3 Shares on a subordinated basis as to: (i) payment of dividends, as and when declared; (ii) payment of amounts due on redemption; and (iii) payment of amounts due on liquidation, dissolution or winding up of CPI Preferred Equity Ltd. If, and for so long as, the declaration or payment of dividends on the Series 1 Shares, Series 2 Shares or Series 3 Shares is in arrears, CPILP will not make any distributions on the CPILP units. See "Capital Structure—Preferred Shares of CPEL" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement.

        The Series 1 Shares and Series 2 Shares will remain outstanding following completion of the Plan of Arrangement in accordance with their terms. CPILP will continue to guarantee the Series 1 Shares, Series 2 Shares and Series 3 Shares on the same terms and conditions as described above and Atlantic Power will provide substantially similar guarantees in the forms attached as Schedule J to the Arrangement Agreement.

Medium Term Notes of CPILP

        CPILP has issued C$210.0 million of 5.95% unsecured medium term notes due June 23, 2036 under a note indenture dated June 15, 2006. See "Capital Structure—Debt Financing" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement. The medium term notes will remain outstanding following completion of the Plan of Arrangement in accordance with their terms and the terms of the note indenture.

Senior Notes of CPI Power (US) GP

        CPI Power (US) GP, a subsidiary of CPILP, has issued an aggregate of $150.0 million principal amount of 5.87% Senior Notes due August 15, 2017 and an aggregate of $75.0 million principal amount of 5.97% Senior Notes due August 15, 2019, each guaranteed by CPILP. See "Capital Structure—Debt Financing" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement. The senior notes will remain outstanding following completion of the Plan of Arrangement in accordance with their terms and will continue to be guaranteed by CPILP.

Curtis Palmer Notes

        Curtis Palmer LLC, a subsidiary of CPILP, has issued $190.0 million principal amount of 5.9% Senior Notes due July 15, 2014 pursuant to an indenture dated June 28, 2004 among CPILP, Curtis Palmer LLC and Deutsche Bank Trust Company Americas. See "Material Contracts" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement. The notes will remain outstanding following completion of the Plan of Arrangement in accordance with their terms and the terms of the indenture.

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SUMMARY OF THE ARRANGEMENT AGREEMENT

        The transaction will be carried out pursuant to the Arrangement Agreement and the Plan of Arrangement. The following is a summary of the principal terms of the Arrangement Agreement and Plan of Arrangement. This summary does not purport to be complete and is qualified in its entirety by reference to the Arrangement Agreement, which is attached as Annex A to this joint proxy statement, and the Plan of Arrangement, which is attached as Schedule A to the Arrangement Agreement. Capitalized terms used in this section and not otherwise defined in this joint proxy statement have the meaning ascribed to them in the Arrangement Agreement.

        On June 20, 2011, Atlantic Power, the General Partner, CPI Investments and CPILP entered into the Arrangement Agreement, pursuant to which the parties agreed that, subject to the terms and conditions set forth in the Arrangement Agreement, Atlantic Power will acquire all of the issued and outstanding CPILP units (directly, or indirectly through the acquisition of all of the outstanding shares of CPI Investment). Upon completion of the Plan of Arrangement, for each CPILP unit held, CPILP unitholders will receive at their election either C$19.40 in cash or 1.3 Atlantic Power common shares, subject to proration. The terms of the Arrangement Agreement are the result of arm's length negotiation between the parties and their respective advisors. Effective July 19, 2011, the Arrangement Agreement was amended to account for the entering into of the Tranche B Facility commitment letter, the termination of a commitment regarding certain bridge loans that Atlantic Power had entered into at the time of entering into the Arrangement Agreement and the correction of certain other references.

Representations and Warranties

        The Arrangement Agreement contains representations and warranties made by the Partnership Entities (the General Partner and CPILP being referred to herein as the "Partnership Entities") to Atlantic Power, by CPI Investments to Atlantic Power and by Atlantic Power to CPILP and CPI Investments Those representations and warranties were made for the purposes of the Arrangement Agreement and are subject to important qualifications and limitations agreed to by the parties in connection with negotiating its terms. Moreover, some of the representations and warranties contained in the Arrangement Agreement are subject to a contractual standard of materiality (including a Material Adverse Effect) that may be different from what might be viewed as material to shareholders of Atlantic Power or unitholders of CPILP, or may have been used for the purpose of allocating risk between parties to an agreement rather than establishing matters of fact. For the foregoing reasons, you should not rely on the representations and warranties contained in the Arrangement Agreement as statements of factual information at the time they were made or otherwise. Information concerning the subject matter of these representations and warranties may have changed since the date of the Arrangement Agreement. Atlantic Power and CPILP will provide additional disclosure in public reports to the extent that they are aware of the existence of any material facts that are required to be disclosed under the applicable securities laws and that might otherwise contradict the terms and information contained in the Arrangement Agreement and will update such disclosure as required by applicable securities laws.

        The representations and warranties provided by the Partnership Entities in favor of Atlantic Power relate to, among other things: (a) board approval, (b) organization, standing and power, (c) authority and absence of conflict, (d) regulatory approvals, (e) interest of the General Partner in CPILP, (f) capital structure of CPILP, (g) subsidiaries of CPILP, (h) existing commitments to issue securities, (i) compliance with laws, (j) permits and licenses, (k) compliance with securities laws and exchange requirements, (l) accuracy of public documents, (m) CPILP financial statements, (n) the financial statements of the General Partner, (o) absence of certain changes, (p) records, (q) assets and undertakings, (r) operation of facilities, (s) material contracts, (t) litigation, (u) environmental matters, (v) benefit plans, (w) intellectual property, (x) tax matters, (y) fees, (z) regulatory status, (aa) internal

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controls and financial reporting, (bb) no undisclosed liabilities, (cc) related party transactions, (dd) registration rights, (ee) insurance, and (ff) Primary Energy Recycling Holdings LLC.

        The representations and warranties provided by CPI Investments in favor of Atlantic Power relate to, among other things: (a) organization, standing and power, (b) authority and absence of conflict, (c) regulatory approvals, (d) capital structure of CPI Investments, (e) CPILP units, (f) subsidiaries, (g) existing commitments to issue securities, (h) compliance with laws, (i) permits and licenses, (j) CPI Investments financial statements, (k) absence of certain changes, (l) records, (m) assets, (n) operation of facilities, (o) material contracts, (p) litigation, (q) benefit plans, (r) intellectual property, (s) tax matters, (t) fees, (u) no undisclosed liabilities, (v) related party transactions, (w) registration rights, (x) insurance, and (y) shareholder and similar agreements.

        The representations and warranties provided by Atlantic Power in favor of CPILP and CPI Investments relate to, among other things: (a) organization, standing and power, (b) authority and absence of conflict, (c) regulatory approvals, (d) capital structure of Atlantic Power, (e) subsidiaries of Atlantic Power, (f) compliance with laws, (g) permits and licenses, (h) compliance with securities laws and exchange requirements, (i) accuracy of public documents, (j) Atlantic Power financial statements, (k) absence of certain changes, (l) records, (m) assets and undertakings, (n) operation of facilities, (o) material contracts, (p) litigation, (q) environmental matters, (r) employee matters, (s) benefit plans, (t) intellectual property, (u) tax matters, (v) fees, (w) commitment letter, (x) funds available, (y) internal controls and financial reporting, (z) related party transactions, (aa) registration rights, (bb) insurance, (cc) board approval and (dd) Registered Retirement Savings Plan eligibility.

Conditions Precedent to the Plan of Arrangement

Mutual Conditions

        The obligations of the parties to complete the transactions contemplated by the Arrangement Agreement are subject to the fulfillment, on or before the Effective Time, of each of the following conditions precedent:

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        The foregoing conditions are for the mutual benefit of the parties and may be waived, in whole or in part, jointly by such parties at any time.

Additional Conditions in Favor of the Partnership Entities

        The obligation of the Partnership Entities to complete the transactions contemplated by the Arrangement Agreement is also subject to the fulfillment of each of the following conditions precedent:

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        The conditions above are for the exclusive benefit of the Partnership Entities and may be asserted by the Partnership Entities regardless of the circumstances or may be waived by the Partnership Entities in their sole discretion, in whole or in part, at any time and from time to time without prejudice to any other rights which the Partnership Entities may have.

Additional Conditions in Favor of CPI Investments

        The obligation of CPI Investments to complete the transactions contemplated by the Arrangement Agreement shall also be subject to the fulfillment of each of the following conditions precedent:

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        The conditions above are for the exclusive benefit of CPI Investments and may be asserted by CPI Investments regardless of the circumstances or may be waived by CPI Investments in its sole discretion, in whole or in part, at any time and from time to time without prejudice to any other rights which CPI Investments may have.

Additional Conditions in Favor of Atlantic Power

        The obligation of Atlantic Power to complete the transactions contemplated by the Arrangement Agreement is also subject to the fulfillment of each of the following conditions precedent:

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        The conditions above are for the exclusive benefit of Atlantic Power and may be asserted by Atlantic Power regardless of the circumstances or may be waived by Atlantic Power in its sole discretion, in whole or in any part, at any time and from time to time without prejudice to any other rights which Atlantic Power may have.

Covenants

General

        In the Arrangement Agreement, each of the Partnership Entities, CPI Investments and Atlantic Power has agreed to certain covenants, including customary affirmative and negative covenants relating to the operation of their respective businesses, and using commercially reasonable efforts to satisfy the conditions precedent to their respective obligations under the Arrangement Agreement.

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Atlantic Power Financing

        Atlantic Power has represented in the Arrangement Agreement that the Tranche B Facility, when funded in accordance with the TLB Commitment Letter, and the available cash of Atlantic Power will provide Atlantic Power with cash proceeds sufficient to pay the cash consideration payable pursuant to the Plan of Arrangement and the fees and expenses of Atlantic Power.

        Atlantic Power has agreed to use commercially reasonable efforts to fulfill and comply with all of its obligations under the TLB Commitment Letter and to satisfy or cause the satisfaction of all of the conditions precedent to the funding of the Tranche B Facility on or before the Effective Date (or such earlier date required by the TLB Commitment Letter).

Non-Solicitation

        Pursuant to the Arrangement Agreement, the Partnership Entities shall not, directly or indirectly, through any officer, director, employee, representative, agent, subsidiary or otherwise:

        The Partnership Entities shall be permitted to engage in discussions or negotiations, provide information and otherwise cooperate with and assist a person making an unsolicited Partnership Acquisition Proposal prior to the CPILP unitholder meeting upon certain conditions, including that the board of directors of the General Partner has determined in good faith, after consultation with its outside legal and financial advisors, that such Partnership Acquisition Proposal constitutes, or would reasonably be expected to lead to, a Superior Proposal and that, based on the advice of outside counsel, the failure to take such action would be inconsistent with its fiduciary duties under applicable laws and the CPILP partnership agreement.

        The Partnership Entities are required, as soon as reasonably practicable (and in any event, within 24 hours) to notify Atlantic Power, at first orally and then in writing, of any proposal, inquiry, offer, expression of interest or request relating to or constituting a Partnership Acquisition Proposal, any request for discussions or negotiations, and any request for non-public information relating to the Partnership Entities received by the Partnership Entities' directors, officers, representatives or agents, or any material amendments to the foregoing.

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        The Partnership Entities may not accept, approve or enter into any agreement (a "Proposed Agreement"), other than a confidentiality and standstill agreement under certain conditions, providing for or to facilitate any Partnership Acquisition Proposal unless:

        During the five business day period described above or such longer period as the Partnership Entities may approve, Atlantic Power shall have the opportunity, but not the obligation, to propose to amend the terms of the Arrangement Agreement and the Plan of Arrangement and the Partnership Entities shall co-operate with Atlantic Power with respect thereto, including negotiating in good faith with Atlantic Power to enable Atlantic Power to make such adjustments to the terms and conditions of the Arrangement Agreement and the Plan of Arrangement as Atlantic Power deems appropriate and as would enable Atlantic Power to proceed with the Plan of Arrangement and any related transactions on such adjusted terms. The board of directors of the General Partner will review any written definitive proposal made by Atlantic Power in good faith to amend the terms of the Plan of Arrangement in order to determine, in good faith in the exercise of its fiduciary duties, whether Atlantic Power's proposal to amend the Plan of Arrangement would result in the Partnership Acquisition Proposal not being a Superior Proposal compared to the proposed amendment to the terms of the Plan of Arrangement. If the board of directors of the General Partner determines that a Partnership Acquisition Proposal is not a Superior Proposal as compared to the proposed amendment to the terms of the Plan of Arrangement, it will promptly enter into the proposed amendment to the Plan of Arrangement.

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        The Arrangement Agreement also includes non-solicitation covenants of CPI Investments and Atlantic Power.

Termination of the Arrangement Agreement

        The Arrangement Agreement may be terminated at any time prior to the Effective Time:

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Termination Payment

        The Arrangement Agreement provides that CPILP will pay to Atlantic Power C$35.0 million (the "Atlantic Power Termination Fee") if:

        The Arrangement Agreement provides that Atlantic Power will pay to CPILP C$35.0 million (the "CPILP Termination Fee") if:

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Expense Payment

        In certain circumstances, if the Arrangement Agreement is terminated (A) CPILP shall be required to pay to Atlantic Power its reasonably incurred out-of-pocket fees; or (B) Atlantic Power shall be required to pay CPILP its reasonably incurred out-of pocket fees, in each case, up to a maximum of C$8.0 million.

Governing Law

        The Arrangement Agreement shall be governed, including as to validity, interpretation and effect, by the laws of the Province of Alberta and the federal laws of Canada applicable therein, and shall be construed and treated in all respects as an Alberta contract.

Summaries of Other Agreements Relating to the Arrangement

Support Agreements

        As part of the Plan of Arrangement, Atlantic Power will acquire all of the outstanding shares of CPI Investments (an entity indirectly owned by Capital Power and EPCOR), the direct and indirect holder of 16,513,504 CPILP units, on effectively the same basis as the acquisition of CPILP units under the Plan of Arrangement. Accordingly, Atlantic Power's willingness to enter into the Arrangement Agreement was subject to, among other things, each of EPCOR, Capital Power and Capital Power LP, the entity through which Capital Power holds its shares of CPI Investments, entering into a support agreement, pursuant to which each shareholder of CPI Investments confirmed its commitment to support the Plan of Arrangement. Contemporaneously with the entering into of the Arrangement Agreement on June 20, 2011, Atlantic Power entered into two support agreements, one with EPCOR and the other with Capital Power LP and Capital Power.

        Among other things, each of Capital Power LP and EPCOR agreed in its respective support agreement to:

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        Given the more active role of Capital Power in the business of Capital Power LP and CPI Investments, the material terms of the support agreement among Atlantic Power, Capital Power LP and Capital Power also include the following:

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        Each support agreement terminates on the earlier of (i) the effective time for the Plan of Arrangement and (ii) the termination of the Arrangement Agreement.

Management Agreements Termination Agreement and Management Agreement Assignment Agreement

        On June 20, 2011, certain subsidiaries of Capital Power entered into an agreement (the "Management Agreements Termination Agreement") with CPILP and certain of its subsidiaries pursuant to which the parties agreed to terminate each of the management and operations agreements between them, other than the Frederickson Agreement (as defined below), effective immediately upon completion of the Plan of Arrangement. In consideration for the termination of the management and operations agreements, CPILP and its subsidiaries agreed to pay to the subsidiaries of Capital Power an aggregate of C$8.5 million.

        On June 20, 2011, a subsidiary of Capital Power entered into an agreement with Atlantic Power and Frederickson Power L.P., a subsidiary of CPILP, pursuant to which the subsidiary of Capital Power agreed to assign its right, benefit, interest and obligation in, to and under the operations and maintenance agreement in respect of CPILP's Frederickson facility (the "Frederickson Agreement") to Atlantic Power. The assignment will be effective immediately upon completion of the Plan of Arrangement. In consideration for the assignment, Atlantic Power has agreed to pay to the subsidiary of Capital Power an aggregate of C$1.5 million. The assignment is conditional on, among other things, receipt of the consent of Puget Sound Energy, Inc. to the assignment.

North Carolina Purchase and Sale Agreement

        On June 20, 2011, a subsidiary of Capital Power entered into a purchase and sale agreement with certain subsidiaries of CPILP, pursuant to which the subsidiary of Capital Power agreed to purchase and the subsidiaries of CPILP agreed to sell all of the membership interests in the limited liability company that owns CPILP's Roxboro and Southport power plants in North Carolina. The purchase price for the membership interests is C$121,405,211. Closing of the purchase and sale will take place on the Effective Date. Closing of the purchase and sale will be conditional on, among other things, receipt of all necessary regulatory approvals and consents, including, without limitation, expiration or early termination of the applicable waiting periods under the Hart-Scott Rodino Antitrust Improvements Act of 1976 and prior authorization from FERC under Section 203 of the United States Federal Power Act.

Employee Hiring and Lease Assignment Agreement

        On June 20, 2011, Atlantic Power, Capital Power and CPO USA entered into an employee hiring and lease assignment agreement pursuant to which Atlantic Power agreed to assume the employment of certain designated employees who perform functions related to CPILP's business. This agreement was necessitated by the fact that neither CPILP nor the General Partner has any employees. Persons performing the functions of employees of CPILP are currently employed by Capital Power and CPO USA rather than directly by CPILP. For further details regarding CPILP employees, see "Business of the Partnership—Employees of the Partnership" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement.

        Pursuant to the agreement, Atlantic Power will (i) be bound by the collective agreements currently in place for Capital Power's unionized employees and, (ii) for certain individuals whose employment is not governed by the collective agreements, Atlantic Power will make offers of employment on

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substantially the same (or better) terms and conditions of employment, in the aggregate, as are in effect on the date of the offer. Existing employee benefits provided by Capital Power will vest on closing of the Plan of Arrangement and be paid out by Capital Power. The agreement also contemplates the negotiation of the assignment of office leases for Capital Power's offices located in the cities of Richmond, B.C., Toronto, Ontario and Chicago, Illinois.

Canadian Pension Transfer Agreement

        On June 20, 2011, Atlantic Power and Capital Power entered into a Canadian pension transfer agreement, pursuant to which Atlantic Power agreed to assume the pension plan assets and obligations from Capital Power related to the employees that it assumes pursuant to the employee hiring and lease assignment agreement described above.

        The agreement primarily relates to the Capital Power Pension Plan (which is a Canadian registered pension plan with both a defined benefit and defined contribution component). For further details regarding Capital Power's pension plan assets and obligations, see "Compensation Discussion and Analysis—Pension Programs" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement. The agreement provides that the assets associated with the pension plan obligations of the employees being transferred to Atlantic Power will be carved out of the Capital Power Pension Plan and transferred to a new plan to be established by Atlantic Power. The new pension plan for Atlantic Power will have equivalent terms to the Capital Power Pension Plan.

        If there is a deficiency in the Capital Power Pension Plan on a going concern basis at the time of closing of the Plan of Arrangement, Capital Power is required to pay Atlantic Power the amount of the deficiency related to the assumed employees (and if there is a surplus, Atlantic Power is required to make a payment to Capital Power). Currently, it is estimated that there is a deficiency of approximately C$2.0 million. Atlantic Power is required to establish savings plans that are substantially the same as certain group RRSPs provided by Capital Power. Capital Power and Atlantic Power will take all commercially reasonable steps to permit transferring employees with balances in Capital Power's Group RRSPs to transfer their assets to Atlantic Power's Group RRSPs.

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MATERIAL CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

        In the opinion of Fraser Milner Casgrain LLP, Canadian counsel to the General Partner, the following is a general summary of the principal Canadian federal income tax considerations generally applicable to a CPILP unitholder that disposes of CPILP units pursuant to the Plan of Arrangement and that, for purposes of the application of the Tax Act and at all relevant times (i) holds CPILP units and will hold any Atlantic Power common shares received pursuant to the Plan of Arrangement as capital property, (ii) deals at arm's length with and is not affiliated with CPILP or Atlantic Power, and (iii) is or is deemed to be resident in Canada (a "Holder" or "Holders"). CPILP units and Atlantic Power common shares will generally constitute capital property to a Holder provided the Holder does not hold such shares in the course of carrying on a business or as part of an adventure in the nature of trade.

        This summary is based on the current provisions of the Tax Act and the regulations thereunder (the "Regulations"), and counsel's understanding of the current administrative policies and assessing practices of the Canada Revenue Agency ("CRA") published in writing prior to the date hereof. This summary takes into account all specific proposals to amend the Tax Act and the Regulations publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof (the "Proposed Amendments"), and assumes that all Proposed Amendments will be enacted in the form proposed. However, no assurances can be given that the Proposed Amendments will be enacted as proposed, or at all. This summary does not otherwise take into account or anticipate any changes in law or administrative policy or assessing practice whether by legislative, administrative or judicial action nor does it take into account tax legislation or considerations of any province, territory or foreign jurisdiction (unless specifically provided for herein), which may differ from those discussed herein.

        This summary is not applicable to a Holder: (i) that is a "specified financial institution," (ii) an interest in which is a "tax shelter investment," (iii) that is a "financial institution" for purposes of certain rules referred to as the mark-to-market rules, (iv) that is exempt from tax under Part I of the Tax Act, or (v) to which the "functional currency" reporting rules apply, each as defined in the Tax Act. Such Holders should consult their own tax advisors with respect to their own particular circumstances.

        This summary is of a general nature only and is not, and is not intended to be, legal or tax advice to any particular Holder. This summary is not exhaustive of all Canadian federal income tax considerations. Accordingly, Holders should consult their own tax advisors having regard to their own particular circumstances.

        Where a Holder jointly makes an election with Atlantic Power under section 85 of the Tax Act (a "Section 85 Election") in respect of its CPILP units as described below, the Atlantic Power common shares received in exchange for such CPILP units will not be "Canadian securities," as defined under subsection 39(6) of the Tax Act, to such Holder and therefore cannot be deemed to be capital property by making an election under subsection 39(4) of the Tax Act. Holders whose CPILP units might not otherwise be considered to be capital property or whose Atlantic Power common shares may not be considered to be capital property should consult their own tax advisors concerning this election.

Disposition of CPILP Units Pursuant to the Plan of Arrangement

Tax-Deferred Rollover Under the Tax Act

        A Holder that exchanges CPILP units for Atlantic Power common shares or a combination of cash and Atlantic Power common shares and is either (i) a resident of Canada for purposes of the Tax Act (other than a person that is exempt from tax under Part I of the Tax Act or that holds its CPILP units in an Exempt Plan, defined below), or (ii) a partnership any member of which is a resident of Canada for purposes of the Tax Act and is not exempt from tax under Part I of the Tax Act (collectively referred to herein as an "Eligible Unitholder"), may make a Section 85 Election with Atlantic Power under subsection 85(1) of the Tax Act, or where the Eligible Unitholder is a partnership, subsection 85(2) of the Tax Act, (and in each case, the corresponding provisions of any applicable

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provincial or territorial tax legislation), and may thereby obtain a full or partial tax-deferred "rollover" for Canadian income tax purposes in respect of its disposition of its CPILP units, depending on the Elected Amount (as defined below) and the adjusted cost base to the Eligible Unitholder of its CPILP units at the time of the exchange, provided the Eligible Unitholder has properly completed and delivered to Atlantic Power the required election forms in the manner and within the time set out below and has properly and timely filed such election forms.

        So long as the adjusted cost base to an Eligible Unitholder of the Eligible Unitholder's CPILP units at the time of the exchange, together with any reasonable costs of disposition, is not less than the Elected Amount, the Eligible Unitholder will not realize a capital gain for purposes of the Tax Act as a result of the exchange. The "Elected Amount" means the amount selected by an Eligible Unitholder in a Section 85 Election to be treated as the proceeds of disposition of its CPILP units, subject to the limitations described below.

        Atlantic Power has agreed to make the Section 85 Election pursuant to subsection 85(1) or 85(2) of the Tax Act (and any similar provision of any provincial legislation) with an Eligible Unitholder at the Elected Amount determined by such Eligible Unitholder, subject to the limitations set out in subsection 85(1) or 85(2) of the Tax Act (or any applicable provincial legislation).

In general, the Elected Amount may not be:

        The tax treatment to an Eligible Unitholder that makes a valid Section 85 Election jointly with Atlantic Power generally will be as follows:

        The income tax consequences described below under "Material Canadian Federal Income Tax Considerations—Taxation of Capital Gains and Capital Losses" will generally apply to a Holder that realizes a capital gain or capital loss from the disposition of CPILP units.

        A tax instruction letter providing certain instructions on how to complete the Section 85 Election may be obtained from the Depositary by checking the appropriate box on the Letter of Transmittal and Election Form and by submitting the Letter of Transmittal to the Depositary on or before the Election Deadline, complying with the procedures set out in section 2.5 of the Plan of Arrangement.

        Eligible Holders that wish to make a Section 85 Election must check the appropriate box on their duly completed and submitted Letter of Transmittal and Election Form. Eligible Holders should note

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that, because of the potential proration of cash and share consideration described above under the heading "The Arrangement Agreement and Plan of Arrangement—Effects of the Plan of Arrangement", they may receive a combination of cash and Atlantic Power common shares in exchange for their CPILP units even if they elect to receive only cash consideration. Eligible Holders that would wish to make a Section 85 Election in such circumstances should check the appropriate box on the duly completed and submitted Letter of Transmittal and Election Form even if they elect to receive cash consideration.

        The signed and properly completed Section 85 Election form of an Eligible Unitholder must be received by Atlantic Power no later than 90 days after the Effective Date. Any Eligible Unitholder that does not ensure that Atlantic Power has received the relevant election form(s) by such date may not be able to benefit from a Section 85 Election. Accordingly, all Eligible Unitholders that wish to make a Section 85 Election with Atlantic Power should give their immediate attention to this matter. With the exception of execution of a Section 85 Election form by Atlantic Power, compliance with the requirements for a valid election will be the sole responsibility of the Eligible Unitholder making the election. Accordingly, none of Atlantic Power, CPILP nor the Depositary will be responsible or liable for taxes, interest, penalties, damages or expenses resulting from the failure by anyone to deliver any election in accordance with the procedures set out in the tax instruction letter, to properly complete any Section 85 Election form(s) or to properly file such forms within the time prescribed and in the form prescribed under the Tax Act (or the corresponding provisions of any applicable provincial or territorial tax legislation).

        An Eligible Unitholder that does not make a valid Section 85 Election (or the corresponding election under any applicable provincial or territorial tax legislation) may realize a taxable capital gain. The comments herein with respect to such elections are provided for general assistance only. Eligible Unitholders wishing to make the Section 85 Election should consult their own tax advisors.

Exchange of CPILP Units Without a Tax-Deferred Rollover

        A Holder that exchanges its CPILP units and that does not make a valid Section 85 Election jointly with Atlantic Power with respect to the exchange will be considered to have disposed of such CPILP units for proceeds of disposition equal to the aggregate of the cash (if any) received on the exchange and the fair market value, at the time of the exchange, of the Atlantic Power common shares (if any) received on the exchange. As a result, the Holder will generally realize a capital gain (or capital loss) to the extent that such proceeds of disposition, net of any reasonable costs of disposition, exceed (or are less than) the adjusted cost base of the Holder's CPILP units immediately before the exchange. Holders will be entitled to increase the adjusted cost base of their CPILP units by the amount of CPILP income allocated by CPILP to such Holders for the 2011 taxation year.

Holding and Disposing of Atlantic Power common shares

Dividends on Atlantic Power common shares

        In the case of a Holder that is an individual, including certain trusts, dividends received or deemed to be received on Atlantic Power common shares will be included in computing the Holder's income and, subject to certain exceptions that apply to trusts, will be subject to the gross-up and dividend tax credit rules applicable to dividends paid by taxable Canadian corporations under the Tax Act, including the enhanced gross-up and dividend tax credit applicable to any dividend designated as an "eligible dividend" in accordance with the provisions of the Tax Act.

        A Holder that is a corporation will be required to include in its income any dividend received or deemed to be received on Atlantic Power common shares, and generally will be entitled to deduct an equivalent amount in computing its taxable income. A Holder that is a "private corporation" (as defined in the Tax Act) or any other corporation controlled, whether because of a beneficial interest in one or more trusts or otherwise, by or for the benefit of an individual (other than a trust) or a related

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group of individuals (other than trusts), will generally be liable to pay a refundable tax of 331/3% under Part IV of the Tax Act on dividends received (or deemed to be received) on the Atlantic Power common shares to the extent such dividends are deductible in computing taxable income for the year.

Disposition of Atlantic Power common shares

        Generally, a Holder that disposes of or is deemed to dispose of an Atlantic Power common share in a taxation year will be subject to the rules described below under "Material Canadian Federal Income Tax Considerations—Taxation of Capital Gains and Capital Losses".

Taxation of Capital Gains and Capital Losses

        Generally, a Holder is required to include in computing its income for a taxation year the amount of any taxable capital gain, which is one-half of the amount of any capital gain realized in the year. Subject to and in accordance with the provisions of the Tax Act, a Holder is permitted to deduct the allowable capital loss, which is one-half of the amount of any capital loss realized in a taxation year, from taxable capital gains realized in the year by such Holder. Allowable capital losses in excess of taxable capital gains may be carried back and deducted in any of the three preceding years or carried forward and deducted in any following year against net taxable capital gains realized in such year to the extent and under the circumstances described in the Tax Act.

        A Holder that is throughout the year a "Canadian controlled private corporation" (as defined in the Tax Act) may be liable to pay, in addition to tax otherwise payable under the Tax Act, a refundable tax on certain investment income including taxable capital gains.

Alternative Minimum Tax

        Taxable capital gains realized and dividends received by a Holder that is an individual or a trust, other than certain specified trusts, may give rise to alternative minimum tax under the Tax Act and such Holders should contact their own tax advisors in this regard.

Eligibility for Investment

        In the opinion of Fraser Milner Casgrain LLP, the Atlantic Power common shares, if issued on the date of this joint proxy statement, would be qualified investments under the Tax Act and the Regulations for a trust governed by a registered retirement savings plan (an "RRSP"), a registered retirement income funds (an "RRIF"), a deferred profit sharing plan, a registered education savings plan, a registered disability savings plan or a tax-free savings account (a "TFSA"), each as defined in the Tax Act ("Exempt Plans").

        Notwithstanding that the Atlantic Power common shares may, at a particular time, be qualified investments for a trust governed by a TFSA, the holder of a TFSA will be subject to a penalty tax with respect to the Atlantic Power common shares held in a TFSA if such shares are "prohibited investments" for the TFSA for the purposes of the Tax Act. Provided that the holder of a TFSA deals at arm's length with Atlantic Power and does not hold a "significant interest" (as defined in the Tax Act) in Atlantic Power or in a corporation, partnership or trust with which Atlantic Power does not deal at arm's length for the purposes of the Tax Act, the Atlantic Power common shares will not be "prohibited investments" for a trust governed by a TFSA.

        On June 6, 2011, the Minister of Finance (Canada) reintroduced certain proposed amendments to the Tax Act that were originally tabled on March 22, 2011 which would extend the application of the rules governing "prohibited investments" and the penalty tax for holding "prohibited investments" to the annuitant of an RRSP or RRIF. No assurance can be given that these proposed amendments to the Tax Act will be enacted as proposed. Holders that intend to hold the Atlantic Power common shares in their TFSA, RRSP or RRIF should consult with their own tax advisors regarding the application of the foregoing prohibited investment rules in their particular circumstances.

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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

        CPILP does not permit non-residents of Canada (as determined for purposes of the Income Tax Act) to hold CPILP units. Accordingly, the following summary does not address the U.S. federal income tax consequences to CPILP unitholders that are U.S. residents or who are otherwise subject to US tax on their worldwide income as a result of their personal circumstances (each, a "US Holder"). Persons who are not US Holders will not be subject to U.S. federal income tax with respect to their CPILP units or Atlantic Power common shares received in exchange therefor unless (1) their income with respect thereto is effectively connected with the conduct of a trade or business in the United States, or (2) such person is an individual who is present in the United States for 183 days or more during the taxable year and has a "tax home" in the United States. Even if a non-US Holder is subject to US federal income tax under either test in the preceding sentence, such person may be eligible for relief from (or reduction to) any US income tax under a tax treaty.

        Persons who may be subject to U.S. federal income tax, including US Holders, should consult their own tax advisors regarding the consequences of the disposition of their CPILP units and the ownership and disposition of Atlantic Power common shares.

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ATLANTIC POWER FINANCING

        Atlantic Power intends to finance the cash portion of the purchase price to complete the Plan of Arrangement by issuing up to approximately C$200.0 million of equity and up to approximately C$425.0 million of debt through public and private offerings. However, in the event that such financing is not available on terms satisfactory to Atlantic Power, Atlantic Power has also delivered to CPILP a copy of an executed letter evidencing the commitment of a Canadian chartered bank and another financial institution to structure, arrange, underwrite and syndicate a senior secured term loan facility in the amount of $625 million (the "Tranche B Facility") subject to the terms and conditions set forth therein. Advances under the Tranche B Facility may be made by way of Base Rate-based loans and LIBOR-based loans. Conditions precedent to funding under the Tranche B Facility include, without limitation, that there shall not have occurred a Material Adverse Effect (as defined in the Arrangement Agreement) in respect of Atlantic Power, CPILP, the General Partner and CPI Investments Inc. taken as a whole.

        Interest for any Base Rate-based loans will be charged at the Base Rate plus a spread and for any LIBOR-based loans, interest will be charged at a rate equal to LIBOR for the corresponding deposits of U.S. dollars plus a spread. The Tranche B Facility will mature on the seventh anniversary following the closing date of the Tranche B Facility. The lenders will be provided with certain collateral, including a first priority security interest in respect of 100% of the units of CPILP and 100% of the shares of the General Partner and any intercompany indebtedness owing by CPILP to Atlantic Power or the General Partner.

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INFORMATION REGARDING ATLANTIC POWER

General

        Atlantic Power is an independent power producer, with power projects located in major markets in the United States. Its current portfolio consists of interests in 12 operational power generation projects across eight states, one wind project under construction in Idaho, a 500 kilovolt 84-mile electric transmission line located in California, and six development projects in five states. Atlantic Power's power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 megawatts (or "MW") in which our ownership interest is approximately 871 MW. Atlantic Power's corporate strategy is to generate stable cash flows from Atlantic Power's existing assets and to make accretive acquisitions to sustain Atlantic Power's dividend payout to shareholders, which is currently paid monthly at an annual rate of C$1.094 per share. Atlantic Power's current portfolio consists of interests in 12 operational power generation projects across nine states, one 53 MW biomass project under construction in Georgia, and an 84-mile, 500 kilovolt electric transmission line located in California. Atlantic Power also owns a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development.

        Atlantic Power sells the capacity and power from its projects under PPAs with a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2012 to 2037, Atlantic Power receives payments for electric energy sold to its customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). Atlantic Power also sells steam from a number of its projects under steam sales agreements to industrial purchasers. The transmission system rights owned by Atlantic Power in its power transmission project entitle it to payments indirectly from the utilities that make use of the transmission line.

        Atlantic Power's projects generally operate pursuant to long-term supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and most of the PPAs and steam sales agreements provide for the pass-through or indexing of fuel costs to Atlantic Power's customers.

        Atlantic Power partners with recognized leaders in the independent power business to operate and maintain its projects, including Caithness Energy LLC, Power Plant Management Services and the Western Area Power Administration. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

        Atlantic Power completed its initial public offering on the TSX in November 2004. At the time of Atlantic Power's initial public offering, its publicly traded security was an income participating security, or an "IPS", each of which was comprised of one common share and C$5.767 principal amount of 11% subordinated notes due 2016. On November 27, 2009, Atlantic Power converted from the IPS structure to a traditional common share structure. In connection with the conversion, each IPS was exchanged for one new common share. Atlantic Power's common shares trade on the TSX under the symbol "ATP" and began trading on the NYSE under the symbol "AT" on July 23, 2010.

Trading Price and Volume

        The Atlantic Power common shares began trading on the TSX on December 2, 2009, under the trading symbol "ATP" and on the NYSE on July 23, 2010 under the trading symbol "AT". The following tables show the monthly range of high and low prices per Atlantic Power common share and the total volume of Atlantic Power common shares traded on the TSX and NYSE during the 12 month period before the date of this joint proxy statement. On                        , 2011, being the last day on which the Atlantic Power common shares traded prior to the date of this joint proxy statement, the

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closing price of the Atlantic Power common shares on the TSX and NYSE was C$            and $            , respectively.

TSX
Date
  High   Low   Volume  

September 2010

  C$ 14.47   C$ 13.36     2,932,970  

October 2010

  C$ 14.33   C$ 13.38     3,761,300  

November 2010

  C$ 14.39   C$ 13.31     2,521,106  

December 2011

  C$ 15.18   C$ 14.12     2,685,937  

January 2011

  C$ 15.43   C$ 14.66     2,163,986  

February 2011

  C$ 15.50   C$ 14.96     1,752,812  

March 2011

  C$ 15.25   C$ 14.41     2,569,639  

April 2011

  C$ 14.86   C$ 13.82     2,126,241  

May 2011

  C$ 15.13   C$ 14.36     1,924,026  

June 2011

  C$ 15.72   C$ 14.51     4,854,845  

July 2011

  C$ 15.46   C$ 14.54     2,493,000  

August 2011

  C$ 15.38   C$ 12.92     3,634,900  

September 1 - 7, 2011

  C$ 15.15   C$ 14.10     666,590  

 

NYSE
Date
  High   Low   Volume  

September 2010

  $ 14.00   $ 12.65     3,437,548  

October 2010

  $ 14.38   $ 13.26     9,451,920  

November 2010

  $ 14.00   $ 13.31     4,155,433  

December 2011

  $ 14.98   $ 13.90     4,227,202  

January 2011

  $ 15.40   $ 14.73     3,585,486  

February 2011

  $ 15.67   $ 15.15     2,893,679  

March 2011

  $ 15.75   $ 14.72     4,245,353  

April 2011

  $ 15.42   $ 14.33     4,064,445  

May 2011

  $ 15.62   $ 14.95     4,855,598  

June 2011

  $ 16.18   $ 14.87     15,174,606  

July 2011

  $ 16.34   $ 15.10     6,353,300  

August 2011

  $ 16.28   $ 13.12     11,733,400  

September 1 - 7, 2011

  $ 15.05   $ 14.65     1,307,152  

        The 6.50% convertible secured debentures of Atlantic Power due October 31, 2014 (the "2006 Debentures") issued pursuant to the trust indenture dated as of October 11, 2006 between Atlantic Power and Computershare Trust Company of Canada as amended by a first supplemental indenture dated as of November 27, 2009 were listed for trading on the TSX on October 11, 2006, under the trading symbol "ATP.DB". The following table shows the range of high and low prices per C$100 principal amount of 2006 Debentures and total monthly volumes traded on the TSX during the 12 month period before the date of this joint proxy statement. On                                    , 2011, being the

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last day on which the 2006 Debentures traded prior to the date of this joint proxy statement, the closing price of the 2006 Debentures on the TSX was C$            .

Date
  High   Low   Volume  

September 2010

  C$ 116.00   C$ 108.25     39,800  

October 2010

  C$ 115.00   C$ 109.50     21,120  

November 2010

  C$ 115.25   C$ 109.00     19,550  

December 2011

  C$ 121.00   C$ 114.45     21,740  

January 2011

  C$ 123.40   C$ 118.92     41,570  

February 2011

  C$ 124.00   C$ 121.16     17,060  

March 2011

  C$ 122.12   C$ 118.60     17,230  

April 2011

  C$ 120.35   C$ 112.31     6,570  

May 2011

  C$ 121.98   C$ 113.82     20,750  

June 2011

  C$ 124.48   C$ 118.11     22,310  

July 2011

  C$ 124.50   C$ 117.54     12,740  

August 2011

  C$ 122.31   C$ 108.58     7,530  

September 1 - 7, 2011

  C$ 120.28   C$ 116.48     810  

        The 6.25% convertible unsecured subordinated debentures of Atlantic Power due March 15, 2017 (the "2009 Debentures") issued pursuant to the trust indenture dated as of December 17, 2009 between Atlantic Power and Computershare Trust Company of Canada were listed for trading on the TSX on December 17, 2009, under the trading symbol "ATP.DB.A". The following table shows the monthly range of high and low prices per C$100 principal amount of 2009 Debentures and total monthly volumes traded on the TSX during the 12 month period before the date of this joint proxy statement. On            , 2011, being the last day on which the 2009 Debentures traded prior to the date of this joint proxy statement, the closing price of the 2009 Debentures on the TSX was C$            .

Date
  High   Low   Volume  

September 2010

  C$ 114.99   C$ 105.17     45,200  

October 2010

  C$ 111.00   C$ 106.15     40,100  

November 2010

  C$ 110.02   C$ 105.50     18,790  

December 2011

  C$ 115.50   C$ 108.86     66,480  

January 2011

  C$ 117.75   C$ 113.21     47,490  

February 2011

  C$ 119.00   C$ 108.92     37,020  

March 2011

  C$ 116.88   C$ 113.80     17,260  

April 2011

  C$ 114.00   C$ 107.45     19,116  

May 2011

  C$ 117.00   C$ 112.00     33,330  

June 2011

  C$ 120.01   C$ 113.00     75,480  

July 2011

  C$ 118.61   C$ 112.18     42,900  

August 2011

  C$ 118.18   C$ 106.85     5,950  

September 1 - 7, 2011

  C$ 117.50   C$ 113.65     430  

        The 5.60% convertible unsecured subordinated debentures of Atlantic Power due June 30, 2017 (the "2010 Debentures") issued pursuant to the first supplemental indenture dated October 20, 2010 to the trust indenture dated December 17, 2009 between Atlantic Power and Computershare Trust Company of Canada were listed for trading on the TSX on October 20, 2010, under the trading symbol "ATP.DB.B". The following table shows the monthly range of high and low prices per C$100 principal amount of 2010 Debentures and total monthly volumes traded on the TSX since the date on which they were issued. On                        , 2011, being the last day on which the 2010 Debentures traded

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prior to the date of this joint proxy statement, the closing price of the 2010 Debentures on the TSX was C$         .

Date
  High   Low   Volume  

October 20 - 31, 2010

  C$ 100.55   C$ 99.90     197,770  

November 2010

  C$ 100.75   C$ 99.90     82,310  

December 2010

  C$ 100.20   C$ 99.60     27,920  

January 2011

  C$ 101.45   C$ 100.00     28,450  

February 2011

  C$ 102.00   C$ 101.00     17,450  

March 2011

  C$ 103.00   C$ 101.15     29,440  

April 2011

  C$ 103.00   C$ 101.00     8,120  

May 2011

  C$ 102.70   C$ 101.25     8,650  

June 2011

  C$ 102.50   C$ 100.61     19,850  

July 2011

  C$ 102.65   C$ 101.40     6,426  

August 2011

  C$ 103.00   C$ 99.75     10,900  

September 1 - 7, 2011

  C$ 102.00   C$ 101.25     6,850  

Prior Sales

        On October 20, 2010, Atlantic Power completed an offering of 2010 Debentures at a price of C$1,000 per 2010 Debenture for total gross proceeds of C$80.5 million, including C$10.5 million aggregate principal amount of debentures pursuant to the exercise in full of the underwriters' over-allotment option.

        On October 20, 2010, Atlantic Power completed an offering of 6,029,000 Atlantic Power common shares, including 784,000 Atlantic Power common shares issued pursuant to the exercise in full of the underwriters' over-allotment option, at a price of US$13.35 per common share.

        On March 31, 2011, Atlantic Power issued 167,928 Atlantic Power common shares in connection with the vesting of notional units previously granted under Atlantic Power's long term incentive plan.

        During the 12 month period before the date of this joint proxy statement, Atlantic Power issued a total of 1,067,836 Atlantic Power common shares on conversion of 2009 Debentures at a conversion price of C$13.00 per common share in accordance with the terms of the indenture governing such 2009 Debentures and a total of 1,209,359 Atlantic Power common shares on conversion of 2006 Debentures at a conversion price of C$12.40 per common share in accordance with the terms of the indenture governing the 2006 Debentures. Details of such issuances are set out below.

Date   Price Per
Atlantic Power
Common Share
  Number of
Atlantic Power
Common Shares
  Reasons for Issuance

8/24/2010

  C$ 13.00     1,307   Conversion of 2009 Debentures

9/15/2010

  C$ 12.40     967   Conversion of 2006 Debentures

10/4/2010

  C$ 12.40     1,935   Conversion of 2006 Debentures

10/25/2010

  C$ 12.40     80,645   Conversion of 2006 Debentures

11/2/2010

  C$ 13.00     8,615   Conversion of 2009 Debentures

11/3/2010

  C$ 13.00     1,923   Conversion of 2009 Debentures

11/9/2010

  C$ 13.00     1,538   Conversion of 2009 Debentures

11/10/2010

  C$ 13.00     769   Conversion of 2009 Debentures

11/12/2010

  C$ 13.00     769   Conversion of 2009 Debentures

11/17/2010

  C$ 13.00     384   Conversion of 2009 Debentures

12/6/2010

  C$ 13.00     692   Conversion of 2009 Debentures

12/14/2010

  C$ 12.40     13,709   Conversion of 2006 Debentures

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Date   Price Per
Atlantic Power
Common Share
  Number of
Atlantic Power
Common Shares
  Reasons for Issuance

12/21/2010

  C$ 13.00     1,923   Conversion of 2009 Debentures

12/23/2010

  C$ 13.00     1,615   Conversion of 2009 Debentures

12/30/2010

  C$ 13.00     220,923   Conversion of 2009 Debentures

12/30/2010

  C$ 12.40     241,371   Conversion of 2006 Debentures

1/19/2011

  C$ 12.40     403   Conversion of 2006 Debentures

1/24/2011

  C$ 12.40     11,532   Conversion of 2006 Debentures

1/26/2011

  C$ 13.00     3,076   Conversion of 2009 Debentures

1/27/2011

  C$ 13.00     197,846   Conversion of 2009 Debentures

1/27/2011

  C$ 12.40     225,161   Conversion of 2006 Debentures

2/2/2011

  C$ 13.00     1,923   Conversion of 2009 Debentures

2/3/2011

  C$ 12.40     645   Conversion of 2006 Debentures

2/9/2011

  C$ 12.40     3,225   Conversion of 2006 Debentures

2/14/2011

  C$ 12.40     2,822   Conversion of 2006 Debentures

2/16/2011

  C$ 12.40     806   Conversion of 2006 Debentures

2/16/2011

  C$ 13.00     1,538   Conversion of 2009 Debentures

2/18/2011

  C$ 12.40     967   Conversion of 2006 Debentures

2/23/2011

  C$ 12.40     403   Conversion of 2006 Debentures

2/24/2011

  C$ 12.40     95,887   Conversion of 2006 Debentures

2/24/2011

  C$ 13.00     207,461   Conversion of 2009 Debentures

2/25/2011

  C$ 13.00     3,384   Conversion of 2009 Debentures

2/25/2011

  C$ 12.40     2,338   Conversion of 2006 Debentures

2/28/2011

  C$ 12.40     153,548   Conversion of 2006 Debentures

2/28/2011

  C$ 13.00     76,923   Conversion of 2009 Debentures

3/29/2011

  C$ 13.00     130,846   Conversion of 2009 Debentures

3/29/2011

  C$ 12.40     120,483   Conversion of 2006 Debentures

3/30/2011

  C$ 12.40     1,532   Conversion of 2006 Debentures

3/30/2011

  C$ 13.00     1,538   Conversion of 2009 Debentures

4/21/2011

  C$ 12.40     1,532   Conversion of 2006 Debentures

4/27/2011

  C$ 13.00     3,846   Conversion of 2009 Debentures

5/13/2011

  C$ 12.40     2,016   Conversion of 2006 Debentures

5/27/2011

  C$ 12.40     16,129   Conversion of 2006 Debentures

5/30/2011

  C$ 12.40     1,612   Conversion of 2006 Debentures

5/31/2011

  C$ 12.40     5,645   Conversion of 2006 Debentures

6/28/2011

  C$ 12.40     70,887   Conversion of 2006 Debentures

6/28/2011

  C$ 13.00     7,538   Conversion of 2009 Debentures

6/29/2011

  C$ 12.40     80   Conversion of 2006 Debentures

7/14/2011

  C$ 13.00     6,153   Conversion of 2009 Debentures

7/27/2011

  C$ 13.00     91,461   Conversion of 2009 Debentures

7/27/2011

  C$ 12.40     81,290   Conversion of 2006 Debentures

7/29/2011

  C$ 13.00     923   Conversion of 2009 Debentures

8/2/2011

  C$ 13.00     91,384   Conversion of 2009 Debentures

8/2/2011

  C$ 12.40     32,274   Conversion of 2006 Debentures

8/8/2011

  C$ 13.00     1,538   Conversion of 2009 Debentures

8/29/2011

  C$ 12.40     21,451   Conversion of 2006 Debentures

Description of Common Shares

        The following summary description sets forth some of the general terms and provisions of the Atlantic Power common shares. Because this is a summary description, it does not contain all of the

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information that may be important to you. For a more detailed description of the Atlantic Power common shares, please refer to the provisions of Atlantic Power's articles.

        Atlantic Power's articles authorize an unlimited number of common shares. At the close of business on            , 2011,             Atlantic Power common shares were issued and outstanding. the Atlantic Power common shares are listed on the TSX under the symbol "ATP" and began trading on the NYSE under the symbol "AT" on July 23, 2010. Holders of Atlantic Power common shares are entitled to receive dividends as and when declared by Atlantic Power's board of directors and are entitled to one vote per Atlantic Power common share on all matters to be voted on at meetings of shareholders. Atlantic Power is limited in its ability to pay dividends on its common shares by restrictions under the BCBCA, relating to Atlantic Power's solvency before and after the payment of a dividend. Holders of Atlantic Power common shares have no pre-emptive, conversion or redemption rights and are not subject to further assessment by Atlantic Power.

        Upon Atlantic Power's voluntary or involuntary liquidation, dissolution or winding up, the holders of Atlantic Power common shares are entitled to share ratably in the remaining assets available for distribution, after payment of liabilities.

        Holders of Atlantic Power common shares will have one vote for each common share held at meetings of common shareholders.

        Pursuant to Atlantic Power's articles and the provisions of the BCBCA, certain actions that may be proposed by Atlantic Power require the approval of its shareholders. Atlantic Power may, by special resolution and subject to its articles, increase its authorized capital by such means as creating shares with or without par value or increasing the number of shares with or without par value. Atlantic Power may, by special resolution, alter its articles to subdivide, consolidate, change from shares with par value to shares without par value or from shares without par value to shares with par value or change the designation of all or any of its shares. Atlantic Power may also, by special resolution, alter its articles to create, define, attach, vary, or abrogate special rights or restrictions to any shares. Under the BCBCA and Atlantic Power's articles, a special resolution is a resolution passed at a duly-convened meeting of shareholders by not less than two-thirds of the votes cast in person or by proxy at the meeting, or a written resolution consented to by all shareholders who would have been entitled to vote at the meeting of shareholders.

Security Ownership of Certain Beneficial Owners and Management

        The following table sets forth information regarding the beneficial ownership of Atlantic Power common shares of the Corporation as of September 7, 2011 with respect to:

        The address of each beneficial owner listed in the following table is c/o Atlantic Power Corporation, 200 Clarendon Street, Floor 25, Boston, MA 02116.

        Except as otherwise indicated in the footnotes to the following table, Atlantic Power believes, based on the information provided to it, that the persons named in the following table have sole voting

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and investment power with respect to the shares they beneficially own, subject to applicable community property laws.

Owner
  Number of Common
Shares beneficially
owned
  Percentage of
Common Shares
beneficially owned(1)
 

Directors and named executive officers

            *

Irving R. Gerstein

    10,400       *

Kenneth M. Hartwick

    57,485 (2)     *

John A. McNeil

    12,500       *

R. Foster Duncan(3)

    1,500       *

Holli Nichols(3)

    2,550 (2)     *

Barry E. Welch

    223,105       *

Paul H. Rapisarda

    40,009       *

William B. Daniels

    7,173       *

John J. Hulburt

    4,643       *

All directors and named executive officers as a group (9 persons)

    359,365     0.01  

Notes:

*
Less than l%.

(1)
The applicable percentage ownership is based on 68,639,654 common shares issued and outstanding as of June 30, 2011.

(2)
Common Shares beneficially owned include units held in the Corporation's Deferred Share Unit Plan of 55,485 for Ken Hartwick and 2,550 for Holli Nichols.

(3)
Joined board of directors in June 2010.

Risk Factors

        The business and operations of Atlantic Power are subject to risks. In addition to considering the other information in this joint proxy statement, CPILP unitholders should consider carefully the factors set forth in the Annual Report on Form 10-K of Atlantic Power for the fiscal year ended December 31, 2010, which has been delivered with, and/or is incorporated by reference into, this joint proxy statement.

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INFORMATION REGARDING CPILP

        The information concerning CPILP contained in this joint proxy statement has been provided by CPILP. Although Atlantic Power has no knowledge that would indicate that any of such information is untrue or incomplete, Atlantic Power does not assume any responsibility for the accuracy or completeness of such information or the failure by CPILP to disclose events which may have occurred or may affect the completeness or accuracy of such information but which are unknown to Atlantic Power.

Presentation of Information

        The information contained herein provides material information about the business, operations and capital of CPILP. Any reference to CPILP means Capital Power Income L.P. and its subsidiaries on a consolidated basis, except where otherwise noted or where the context otherwise dictates. All financial information with respect to CPILP is presented in Canadian dollars unless otherwise stated.

General

        CPILP (formerly known as EPCOR Power L.P. and prior thereto, TransCanada Power, L.P.) was formed pursuant to a limited partnership agreement dated as of March 27, 1997 and as amended and restated June 6, 1997 and as amended September 29, 1998, March 26, 2004, April 29, 2004 and August 31, 2005 and as amended and restated July 1, 2009, October 1, 2009 and November 4, 2009 among the general partner of CPILP (CPI Income Services Ltd., formerly known as TransCanada Power Services Ltd.), the initial limited partner and each person who is admitted to CPILP as a limited partner in accordance with the terms of the limited partnership agreement. On March 27, 1997, CPILP was registered as a limited partnership under the laws of the Province of Ontario and was registered or extra-provincially registered, as the case may be, in all other provinces of Canada. The head office of CPILP is located at 10065 Jasper Avenue, Edmonton, Alberta, T5J 3B1. The registered office of CPILP is 200 University Avenue, Toronto, Ontario, M5H 3C6.

        CPILP is only permitted to carry on activities that are directly or indirectly related to the energy supply industry and to hold investments in other entities which are primarily engaged in such industry. CPILP's portfolio consists of 19 wholly-owned power generation assets located in both Canada (in the provinces of British Columbia and Ontario) and in the United States (in the states of California, Colorado, Illinois, New Jersey, New York and North Carolina), a 50.15% interest in a power generation asset in Washington State (collectively the power plants), and a 14.3% common equity interest in Primary Energy Recycling Holdings LLC.

        The general partner of CPILP is responsible for the management of CPILP. The General Partner has engaged the Managers, both subsidiaries of Capital Power, to perform management and administrative services for CPILP and to operate and maintain the power plants pursuant to certain management and operations agreements.

        For further information regarding CPILP, its subsidiaries and their respective business activities, including CPILP's inter-corporate relationships and organizational structure, see "Additional Information Regarding CPILP" included in CPILP's Annual Information Form dated March 11, 2011, which is delivered with, and/or incorporated by reference into, this joint proxy statement.

Recent Developments

Termination of Dividend Reinvestment Plan

        CPILP terminated its Premium Distribution and Distribution Reinvestment Plan effective June 30, 2011.

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Power Purchase Agreements Finalized for the North Carolina Plants

        In June 2011, CPILP executed final power purchase agreements with Progress Energy for CPILP's Southport and Roxboro facilities. The final power purchase agreements, which expire in 2021, replace the interim power purchase agreements that were effective April 1, 2011 and contain terms that are generally consistent with the interim power purchase agreements.

Power Purchase Agreement Amendment for the Calstock Plant

        The power purchase agreement for CPILP's Calstock facility was amended effective May 1, 2011 to increase the price for power delivered during peak power demand periods and to reduce the power the power purchase agreement counterparty is required to purchase during periods of low power demand.

Additional Information Relating to CPILP

        The following documents, which have been filed by CPILP with the Canadian Securities Administrators, are specifically delivered with, and/or incorporated by reference into, this joint proxy statement:

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Price Range and Trading Volume of CPILP Units

        The CPILP units are listed and trade on the TSX under the trading symbol "CPA.UN". The following table sets forth the price range and trading volume of the CPILP units as reported by the TSX for the periods indicated.

Month
  High
($)
  Low
($)
  Close
($)
  Volume
Traded
 

2010

                         

June

    16.59     15.38     16.30     1,834,995  

July

    17.90     16.03     17.68     1,470,997  

August

    18.01     16.96     18.01     1,275,618  

September

    18.85     17.65     18.75     1,433,610  

October

    19.02     17.81     18.33     1,395,389  

November

    18.54     17.75     17.91     1,497,626  

December

    18.10     17.11     17.95     1,566,002  

2011

                         

January

    19.83     17.65     19.60     1,495,356  

February

    20.70     19.15     20.17     1,453,180  

March

    21.22     17.87     20.90     2,092,101  

April

    20.49     19.25     19.26     1,295,173  

May

    19.80     18.28     19.80     1,458,674  

June

    19.77     18.63     19.00     4,174,124  

July

    19.50     18.94     19.10     2,384,335  

August

    19.32     17.23     19.15     1,712,412  

September (to September 7)

    19.13     18.50     18.96     157,041  

        On June 17, 2011, the last trading day on which the CPILP units traded prior to the announcement of entering into the Arrangement Agreement, the closing price of the CPILP units on the TSX was $18.63. On                        , 2011, the last trading day on which the CPILP units traded prior to mailing this joint proxy statement, the closing price of the CPILP units on the TSX was $            .

Dividend History

Distributions of CPILP

        The following table sets forth the cash distributions declared (on a per unit basis) in respect of the CPILP units during the prior two years:

 
  2011
(to September 7)
  2010   2009  

Cash distributions per CPILP unit

  $ 1.32   $ 1.76   $ 1.95  

        Prior to October 1, 2009, CPILP distributed cash to its limited partners on a quarterly basis. Commencing after September 30, 2009, CPILP distributes cash to its limited partners on a monthly basis in accordance with the requirements of the limited partnership agreement and subject to the approval of the board of directors of the general partner of CPILP. Cash distributions are determined after considering cash amounts required for the operations of CPILP and the power plants, including maintenance capital expenditures, debt repayments, and financing charges, and any cash retained at the discretion of the general partner of CPILP to satisfy anticipated obligations or to normalize monthly distributions.

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Dividends of Subsidiary (CPI Preferred Equity Ltd.)

        Dividends are also declared in respect of preferred shares issued by CPI Preferred Equity Ltd., which is a wholly-owned subsidiary of CPILP. Cash dividends per share declared by CPI Preferred Equity Ltd. in respect of its Cumulative Redeemable Preferred Shares, Series 1, and its Cumulative Rate Reset Preferred Shares, Series 2 during the prior two years are set forth in the following table:

 
  2011
(to September 7)
  2010   2009  

Cash distributions per Series 1 Preferred Share

  $ 0.909375   $ 1.2125   $ 1.2125  

Cash distributions per Series 2 Preferred Share

  $ 1.3125   $ 1.75   $ 0.28288 (1)

Note:

(1)
Represents the period from November 2, 2009 to December 31, 2009.

Voting Securities and Principal Holders of Voting Securities

        The authorized capital of CPILP consists of an unlimited number of CPILP units and an unlimited number of subscription receipts exchangeable into CPILP units. As of September 7, 2011, CPILP had outstanding 56,597,899 CPILP Units, each of which carries the right to one vote on all matters that may come before the CPILP special meeting. To the knowledge of the directors and executive officers of the general partner of CPILP, the only persons or companies beneficially owning, directly or indirectly, or controlling or directing securities carrying 10% or more of the voting rights attached to any class of outstanding voting securities of CPILP is set forth in the following table:

Shareholder
  Type of
Ownership
  Number of
Shares
  (%)  

CPI Investments Inc.(1)

  Direct & Indirect     16,513,504     29.18 %

Note:

(1)
CPI Investments holds 16,511,104 CPILP units and all of the issued and outstanding shares of the General Partner, which holds 2,400 CPILP units. Capital Power, indirectly through Capital Power L.P., holds a 49% voting interest and 100% economic interest in CPI Investments and EPCOR holds the remaining 51% voting interest in CPI Investments.

Ownership of CPILP Securities by Directors, Officers and Insiders

        To the knowledge of CPILP, after reasonable inquiry, the following table indicates, as of September 7, 2011, the number of CPILP units beneficially owned, directly or indirectly, or over which control or direction is exercised, by: (i) each director and officer of CPILP; (ii) each associate or

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affiliate of an insider of CPILP; (iii) each associate or affiliate of CPILP; (iv) each insider of CPILP (other than a director or officer of CPILP; and (v) each person acting jointly or in concert with CPILP:

Name
  Position with CPILP   CPILP
Units
  Maximum
Amount of
Potential Cash
Consideration
 

Graham L. Brown

  Director         n/a  

Brian A. Felesky

  Director (Independent)     5,640   $ 109,416  

Allen R. Hagerman

  Director (Independent)     17,702   $ 343,419  

Francois L. Poirier

  Director (Independent)     3,100   $ 60,140  

Brian T. Vaasjo

  Chairman and Director     7,400   $ 143,560  

Rodney D. Wimer

  Director (Independent)         n/a  

James Oosterbaan

  Director         n/a  

Stuart A. Lee

  Director and President     3,536   $ 68,598  

B. Kathryn Chisholm

  General Counsel and Corporate Secretary     915   $ 17,751  

Peter D. Johanson

  Controller     400   $ 7,760  

Leah M. Fitzgerald

  Assistant Corporate Secretary         n/a  

Anthony Scozzafava

  Chief Financial Officer     2,050   $ 39,770  

Yale Loh

  Vice President, Treasurer         n/a  

Capital Power Corporation(1)

  Unitholder     16,513,504   $ 320,361,978  

(1)
Capital Power indirectly owns 49% of the voting interests and all of the economic interests in CPI Investments. EPCOR owns the remaining 51% voting interest in CPI Investments. CPI Investments owns 16,513,504 CPILP units. Under the Plan of Arrangement, Atlantic Power will acquire all of the outstanding shares of CPI Investments on effectively the same basis as the acquisition of CPILP units under the Plan of Arrangement.

Indebtedness of Directors and Executive Officers

        No executive officers, directors, employees or former executive officers, directors or employees of CPILP or any of its subsidiaries, nor any associate of any one of them, is currently or will be indebted to CPILP, the general partner of CPILP or any of its subsidiaries upon completion of the Plan of Arrangement.

Risk Factors

        An investment in CPILP units or other securities of CPILP is subject to certain risks. The transactions contemplated by the Arrangement Agreement and the Plan of Arrangement are also subject to certain risks. Investors should carefully consider the risk factors described under the heading "Risk Factors" included in CPILP's Annual Information Form of CPILP dated March 11, 2011 and under the heading "Business Risks" included in CPILP's Management's Discussion and Analysis for the Year Ended December 31, 2010, as well as the risk factors set forth elsewhere in this joint proxy statement.

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Auditors, Transfer Agent and Registrar

        The auditors of CPILP are KPMG LLP, Independent Registered Chartered Accountants, Calgary, Alberta. CPILP's transfer agent and registrar is Computershare Trust Company of Canada at its principal offices in Calgary and Toronto.

Selected Historical Consolidated Financial Data of CPILP

        The following table presents selected consolidated financial information for CPILP. The selected historical financial data as of, and for the years ended, December 31, 2010, 2009 and 2008 has been derived from CPILP's audited consolidated financial statements for those periods appearing elsewhere in this joint proxy statement. The selected historical financial data as of, and for the years ended, December 31, 2007 and 2006 has been derived from the audited consolidated financial statements of CPILP not appearing in this joint proxy statement. The selected historical financial data as of, and for the periods ended, June 30, 2011 and 2010 are derived from CPILP's unaudited consolidated financial statements for those periods appearing elsewhere in this joint proxy statement.

        Data for all periods presented below have been prepared under Canadian generally accepted accounting principles and are reported in Canadian dollars. You should read the following selected consolidated financial data together with CPILP's consolidated financial statements and the notes thereto and the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations" for CPILP included elsewhere in this joint proxy statement.

 
  Year Ended December 31,   Six months ended June 30,  
(in thousands of Canadian dollars,
except as otherwise stated)
  2010   2009   2008   2007   2006   2011(a)(b)   2010(a)  
 
  $
  $
  $
  $
  $
  $
  $
 

Revenue

  $ 532,377   $ 586,491   $ 499,267   $ 549,872   $ 326,900   $ 261,524   $ 241,453  

Depreciation, amortization and accretion

  $ 98,227   $ 93,249   $ 88,313   $ 85,553   $ 65,200   $ 45,461   $ 49,806  

Financial charges and other, net

  $ 40,179   $ 46,462   $ 94,836   $ 8,574   $ 42,200   $ 21,457   $ 18,879  

Net income before tax and preferred share Dividends

  $ 35,224   $ 56,812   $ (91,918 ) $ 108,953   $ 67,400   $ 18,741   $ 2,988  

Net income (loss) attributable to equity holders of CPILP

  $ 30,500   $ 57,553   $ (67,893 ) $ 30,816   $ 62,121   $ 10,529   $ 5,335  

Basic and diluted earning (loss) per unit, C$

  $ 0.55   $ 1.07   $ (1.26 ) $ 0.59   $ 1.28   $ 0.19   $ 0.10  

Distributions declared per unit, C$

  $ 1.76   $ 1.95   $ 2.52   $ 2.52   $ 2.52   $ 0.88   $ 0.88  

Total assets

  $ 1,583,910   $ 1,668,057   $ 1,809,225   $ 1,852,573   $ 1,883,400   $ 1,471,772   $ 1,657,926  

Total long-term liabilities

  $ 874,190   $ 853,314   $ 935,248   $ 730,940   $ 757,800   $ 821,382   $ 883,863  

Operating margin

 
$

187,567
 
$

211,680
 
$

111,446
 
$

216,188
 
$

185,900
 
$

99,675
 
$

77,276
 

(a)
Unaudited

(b)
Results for 2011 have been prepared using International Financial Reporting Standards.

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        Under U.S. GAAP, the following differences are noted:

 
  Years Ended December 31,  
(in thousands of Canadian dollars, except as otherwise stated)
  2010   2009  

Revenue

  $ 532,377   $ 586,491  

Depreciation, amortization and accretion

  $ 98,277   $ 93,249  

Financial charges and other, net

  $ 40,129   $ 46,462  

Net income before tax and preferred share dividends

  $ 39,179   $ 54,753  

Net income (loss) attributable to equity holders of CPILP

  $ 34,455   $ 55,529  

Basic and diluted earning (loss) per unit, C$

  $ 0.63   $ 1.03  

Distributions declared per unit, C$

  $ 1.76   $ 1.95  

Total assets

  $ 1,588,352   $ 1,673,059  

Total long-term liabilities

  $ 878,632   $ 858,317  

Operating margin

 
$

191,530
 
$

209,621
 

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INFORMATION REGARDING THE COMBINED COMPANY

General

        On completion of the Plan of Arrangement, Atlantic Power will continue to be a corporation governed by the laws of the Province of British Columbia and CPILP will continue to be a limited partnership governed by the laws of the Province of Ontario. After the Effective Date, Atlantic Power will directly or indirectly own all of the outstanding CPILP units.

        Upon completion of the Plan of Arrangement, CPILP's operations will be managed and operated as a subsidiary of Atlantic Power.

Directors and Executive Officers of the Combined Company

        Following completion of Plan of Arrangement, it is anticipated that the senior management and the board of directors of the Combined Company will initially be comprised of the existing senior management and board of directors of Atlantic Power.

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ATLANTIC POWER AND CPILP UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

        The unaudited pro forma condensed combined statements of income (which we refer to as the pro forma financial statements) combine the historical consolidated financial statements of Atlantic Power and CPILP to illustrate the effect of the Plan of Arrangement. The pro forma financial statements were based on and should be read in conjunction with the:

        The historical consolidated financial statements have been adjusted in the pro forma financial statements to give effect to pro forma events that are (1) directly attributable to Plan of Arrangement, (2) factually supportable and (3) with respect to the unaudited pro forma condensed combined consolidated statement of operations (which we refer to as the pro forma statement of operations), expected to have a continuing impact on the combined results. The pro forma statements of operations for the year ended December 31, 2010 and for the six months ended June 30, 2011, give effect to the Plan of Arrangement as if it occurred on January 1, 2010. The Unaudited Pro Forma Condensed Combined Consolidated Balance Sheet (which we refer to as the pro forma balance sheet) as of June 30, 2011, gives effect to the Plan of Arrangement as if it occurred on June 30, 2011.

        As described in the accompanying notes, the pro forma financial statements have been prepared using the acquisition method of accounting under existing United States generally accepted accounting principles, or GAAP, and the regulations of the SEC. Atlantic Power has been treated as the acquirer in the transaction for accounting purposes. The acquisition accounting is dependent upon certain valuations and other studies that have yet to commence or progress to a stage where there is sufficient information for a definitive measurement. Accordingly, the pro forma financial statements are preliminary and have been made solely for the purpose of providing unaudited pro forma condensed combined consolidated financial information. Differences between these preliminary estimates and the final acquisition accounting will occur and these differences could have a material impact on the accompanying pro forma financial statements and the combined company's future results of operations and financial position.

        The pro forma financial statements have been presented for informational purposes only and are not necessarily indicative of what the combined company's results of operations and financial position would have been had the transaction been completed on the dates indicated. In addition, the pro forma financial statements do not purport to project the future results of operations or financial position of the combined company.

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED STATEMENT OF OPERATIONS

For the Six Months Ended June 30, 2011
(in thousands, except per share data)

 
  Atlantic
Power
Historical
(unaudited)(a)
  CPILP
Historical
(unaudited)(a)(1)
  Pro Forma
Adjustments(b)
  Pro Forma
Combined
 

Project revenue:

  $ 106,923   $ 257,148   $ (18,056 )(d) $ 346,015  

Project expenses:

                         
 

Fuel

    31,384     145,152     (10,308 )(d)   166,228  
 

Operations and maintenance

    18,873     16,997     (10,416 )(d)   25,454  
 

Depreciation and amortization

    21,803     45,461     19,485 (c),(d),(e)   86,749  
                   

    72,060     207,610     (1,239 )   278,431  

Project other income (expense):

                         
 

Change in fair value of derivative instruments

    (1,013 )   299     17     (697 )
 

Equity in earnings of unconsolidated affiliates

    3,273             3,273  
 

Interest expense, net

    (9,190 )           (9,190 )
 

Other expense, net

    (33 )           (33 )
                   

    (6,963 )   299     17     (6,647 )
                   

Project income

    27,900     49,837     (16,800 )   60,937  

Administrative and other expenses (income):

                         
 

Administration

    8,725     14,016     (350 )(d)   22,391  
 

Interest expense, net

    7,478     21,430     13,397 (c),(f)   42,305  
 

Foreign exchange gain

    (1,193 )   (4,351 )   (91 )   (5,635 )
                   

    15,010     31,095     12,956     59,061  
                   

Income (loss) from operations before income taxes

    12,890     18,742     (29,756 )   1,876  

Income tax expense (benefit)

    (6,161 )   1,159     (12,939 )(e),(i)   (17,941 )
                   

Net income (loss)

    19,051     17,583     (16,817 )   19,817  

Net (loss) income attributable to noncontrolling interest

    (271 )   7,054     169     6,952  
                   

Net income (loss) attributable to Atlantic Power Corporation/CPILP

  $ 19,322   $ 10,529   $ (16,986 ) $ 12,865  
                   

Net income (loss) per share attributable to Atlantic Power Corporation shareholders / CPILP unitholders:

                         
 

Basic

  $ 0.28   $ 0.19   $ (0.36 ) $ 0.11  
 

Diluted

  $ 0.28   $ 0.19   $ (0.36 ) $ 0.11  

(1)
The CPILP historical results are in recorded in Canadian dollars and are in accordance with IFRS.

See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2010
(in thousands, except per share data)

 
  Atlantic
Power
Historical
(unaudited)(a)
  CPILP
Historical
(unaudited)(a)(1)
  Pro Forma
Adjustments(b)
  Pro Forma
Combined
 

Project revenue:

  $ 195,256   $ 524,569   $ (49,840 )(d) $ 669,985  

Project expenses:

                         
 

Fuel

    65,553     219,218     (27,387 )(c),(d)   257,384  
 

Operations and maintenance

    31,237     114,164     (18,908 )(d)   126,493  
 

Depreciation and amortization

    40,387     98,277     28,604 (d),(e)   167,268  
                   

    137,177     431,659     (17,691 )   551,145  

Project other income (expense):

                         
 

Change in fair value of derivative instruments

    (14,047 )   (11,421 )   468     (25,000 )
 

Equity in earnings of unconsolidated affiliates

    15,288             15,288  
 

Interest expense, net

    (17,660 )           (17,660 )
 

Other expense, net

    219             219  
                   

    (16,200 )   (11,421 )   468     (27,153 )
                   

Project income

    41,879     81,489     (31,681 )   91,687  

Administrative and other expenses (income):

                         
 

Administration

    16,149     13,945     (2,292 )(d)   27,802  
 

Interest expense, net

    11,701     40,129     26,771 (d),(f)   78,601  
 

Foreign exchange gain

    (1,014 )   (7,808 )   234 (c)   (8,588 )
 

Other (income)

    (26 )       (1,121 )(d)   (1,147 )
                   

    26,810     46,266     23,592     96,668  
                   

Income (loss) from operations before income taxes

    15,069     35,223     (55,273 )   (4,981 )

Income tax expense (benefit)

    18,924     (9,384 )   (25,656 )(e),(i)   (16,116 )
                   

Net income (loss)

    (3,855 )   44,607     (29,617 )   11,135  

Net (loss) income attributable to noncontrolling interest

    (103 )   14,107     (407 )   13,597  
                   

Net income (loss) attributable to Atlantic Power Corporation/CPILP

  $ (3,752 ) $ 30,500   $ (29,210 ) $ (2,462 )
                   

Net income (loss) per share attributable to Atlantic Power Corporation shareholders/CPILP unitholders:

                         
 

Basic

  $ (0.06 ) $ 0.55   $ (0.51 ) $ (0.02 )
 

Diluted

  $ (0.06 ) $ 0.55   $ (0.51 ) $ (0.02 )

(1)
The CPILP historical results are in recorded in Canadian dollars and are in accordance with Canadian GAAP.

See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.
UNAUDITED PRO FORMA CONDENSED COMBINED
CONSOLIDATED BALANCE SHEET

As of June 30, 2011
(in thousands)

 
  Atlantic
Power
Historical
(unaudited)(a)
  CPILP
Historical
(unaudited)(a)(1)
  Pro Forma
Adjustments(b)
  Pro Forma
Combined
 

Assets

                         

Current assets:

                         
 

Cash and cash equivalents

  $ 46,551   $ 12,826   $ 86,032 (d),(f) $ 145,409  
 

Restricted cash

    21,034             21,034  
 

Accounts receivable

    20,028     48,749     1,805     70,582  
 

Note receivable—related party

    7,326             7,326  
 

Current portion of derivative instruments asset

    9,297     13,021     482     22,800  
 

Prepayments, supplies, and other

    8,451     18,143     672     27,266  
 

Asset held for sale

        130,613     (130,613 )(d)    
 

Refundable income taxes

    1,611             1,611  
                   
 

Total current assets

    114,298     223,352     (41,622 )   296,028  

Property, plant, and equipment, net

   
308,051
   
835,881
   
204,252

(c),(e)
 
1,348,184
 

Transmission system rights

    184,208             184,208  

Equity investments in unconsolidated affiliates

    276,962     31,344     1,160     309,466  

Other intangible assets, net

    77,425     270,441     363,179 (c),(e)   711,045  

Goodwill

    12,453     19,689     421,639 (c),(h)   453,781  

Derivative instruments asset

    18,865     32,710     1,211     52,786  

Deferred income taxes

        20,337     19,459 (c),(i)   39,796  

Other assets

    16,718     38,018     6,448 (c),(f)   61,184  
                   
 

Total assets

  $ 1,008,980   $ 1,471,772   $ 975,726   $ 3,456,478  
                   

Liabilities

                         

Current Liabilities:

                         
 

Accounts payable and accrued liabilities

  $ 16,333   $ 59,423   $ 27,557 (c),(g) $ 103,313  
 

Liabilities held for sale

        15,367     (15,367 )(d)    
 

Current portion of long-term debt

    21,962             21,962  
 

Current portion of derivative instruments liability

    7,410     23,138     857     31,405  
 

Interest payable on convertible debentures

    1,948             1,948  
 

Dividends payable

    6,490             6,490  
 

Other current liabilities

    7             7  
                   
 

Total current liabilities

    54,150     97,928     13,047     165,125  

Long-term debt

   
263,111
   
675,465
   
454,420

(c),(f)
 
1,392,996
 

Convertible debentures

    209,703             209,703  

Derivative instruments liability

    24,822     79,686     2,950     107,458  

Deferred income taxes

    23,594     17,200     150,812 (c),(i)   191,606  

Other non-current liabilities

    2,121     49,031     (21,082 )(c)   30,070  

Equity

                         
 

Common shares

    644,001     332,301     345,079 (f),(j)   1,321,381  
 

Accumulated other comprehensive loss

    24             24  
 

Retained deficit

    (215,782 )       23,048 (g),(i)   (192,734 )
                   

Total shareholders' equity

    428,243     332,301     368,127     1,128,671  
                   

Noncontrolling interest

    3,236     220,161     7,452 (c)   230,849  
                   

Total equity

    431,479     552,462     375,579     1,359,520  
                   

Total liabilities and equity

  $ 1,008,980   $ 1,471,772   $ 975,726   $ 3,456,478  
                   

(1)
The CPILP historical results are in recorded in Canadian dollars and are in accordance with IFRS

See accompanying Notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, which are an integral part of these statements.

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Description of the Transaction

        On June 20, 2011, Atlantic Power, CPILP, the General Partner and CPI Investments entered into the Arrangement Agreement, which provides that Atlantic Power will acquire, directly or indirectly, all of the issued and outstanding CPILP units pursuant to a court-approved statutory Plan of Arrangement under the CBCA. Under the terms of the Plan of Arrangement, CPILP unitholders will be permitted to exchange each of their CPILP units for, at their election, C$19.40 in cash or 1.3 Atlantic Power common shares. All cash elections will be subject to proration if total cash elections exceed approximately C$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares.

        Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power, for approximately C$121.0 million. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power and CPILP and certain subsidiaries of CPILP will be terminated (or assigned to Atlantic Power) in consideration of a payment of C$10 million. Atlantic Power will assume the management of CPILP and enter into a transitional services agreement with Capital Power for a term of up to 12 months following closing, which will facilitate the integration of CPILP into Atlantic Power.

Note 2. Basis of Pro Forma Presentation

        The pro forma financial statements were derived from historical consolidated financial statements of Atlantic Power and CPILP. Certain reclassifications have been made to the historical financial statements of CPILP to conform with Atlantic Power's presentation. This resulted in income statement adjustments to operating revenues, operating expenses, other income and deductions and balance sheet adjustments to current assets, long term assets, current liabilities and other long term liabilities.

        The historical consolidated financial statements have been adjusted in the pro forma financial statements to give effect to pro forma events that are (1) directly attributable to the transaction, (2) factually supportable, and (3) with respect to the pro forma statement of operations, expected to have a continuing impact on the combined results. The following matters have not been reflected in the pro forma financial statements as they do not meet the aforementioned criteria.

        The pro forma financial statements were prepared using the acquisition method of accounting under GAAP and the regulations of the SEC. Atlantic Power has been treated as the acquirer in the transaction for accounting purposes. Acquisition accounting requires, among other things, that most assets acquired and liabilities assumed be recognized at fair value as of the acquisition date. In

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2. Basis of Pro Forma Presentation (Continued)


addition, acquisition accounting establishes that the consideration transferred be measured at the closing date of the transaction at the then-current market price. Since acquisition accounting is dependent upon certain valuations and other studies that have yet to commence or progress to a stage where there is sufficient information for a definitive measurement, the pro forma financial statements are preliminary and have been prepared solely for the purpose of providing unaudited pro forma condensed combined consolidated financial information. Differences between these preliminary estimates and the final acquisition accounting will occur and these differences could have a material impact on the accompanying pro forma financial statements and the combined company's future results of operations and financial position.

Note 3. Significant Accounting Policies

        Based upon Atlantic Power's initial review of CPILP's summary of significant accounting policies, as disclosed in the CPILP consolidated historical financial statements elsewhere in this joint proxy statement, as well as on preliminary discussions with CPILP's management, the pro forma combined consolidated financial statements assume there will be significant adjustments necessary to conform CPILP's accounting policies under International Financial Reporting Standards ("IFRS") to Atlantic Power's accounting policies under US GAAP. Upon completion of the transaction and a more comprehensive comparison and assessment, differences may be identified that would necessitate changes to CPILP's future accounting policies and such changes could result in material differences in future reported results of operations and financial position for CPILP as compared to historically reported amounts.

Note 4. Estimated Purchase Price and Preliminary Purchase Price Allocation

        Atlantic Power is proposing to acquire all of the outstanding units of CPILP for a combination of either C$19.40 in cash or 1.3 Atlantic Power shares per CPILP unit. The purchase price for the business combination is estimated as follows (in thousands except conversion ratio and share price):

Fair value of consideration transferred:

       
 

Cash

  $ 525,689  
 

Equity

    487,480  
       

Total estimated purchase price

    1,013,169  

Preliminary purchase price allocation

       
 

Working capital

  $ 10,932  
 

Property, plant and equipment

    1,040,133  
 

Intangibles

    633,620  
 

Other long-term assets

    129,883  
 

Long-term debt

    (704,885 )
 

Other long-term liabilities

    (110,585 )
 

Deferred tax liability

    (199,644 )
       
 

Total identifiable net assets

    799,454  
 

Noncontrolling interest

    (227,613 )
 

Goodwill

    441,328  
       

Total estimated purchase price

  $ 1,013,169  

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4. Estimated Purchase Price and Preliminary Purchase Price Allocation (Continued)

        The preliminary purchase price was computed using CPILP's outstanding units as of June 30, 2011, adjusted for the exchange ratio. The preliminary purchase price reflects the market value of Atlantic Power's common stock to be issued in connection with the transaction based on the closing price of Atlantic Power's common stock on June 30, 2011.

        The allocation of the preliminary purchase price to the fair values of assets acquired and liabilities assumed includes pro forma adjustments to reflect the fair values of CPILP's assets and liabilities at the time of the completion of the transaction. The final allocation of the purchase price could differ materially from the preliminary allocation used for the Unaudited Pro Forma Condensed Combined Consolidated Balance Sheet primarily because power market prices, interest rates and other valuation variables will fluctuate over time and be different at the time of completion of the transaction compared to the amounts assumed in the pro forma adjustments.

Note 5. Pro Forma Adjustments to Financial Statements

        The pro forma adjustments included in the pro forma financial statements are as follows:

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5. Pro Forma Adjustments to Financial Statements (Continued)

 
  Six months ended
June 30, 2011
  Year ended
December 31, 2010
 

Project revenue

  $ 24,210   $ 34,726  

Project expenses

             
 

Fuel

    13,787     24,816  
 

Project operations and maintenance

    10,843     15,916  
 

Depreciation and amortization

    4,539     8,936  
           

    29,169     49,668  
           

Project loss

    (4,959 )   (14,942 )

Administration

    1,032     3,438  
           

Net loss

  $ (5,991 ) $ (18,380 )
           

 

 
  As of
June 30, 2011
 

Asset held for sale

  $ 130,613  

Liabilities held for sale

    (15,367 )
       

Retained earnings

  $ 115,246  
       

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5. Pro Forma Adjustments to Financial Statements (Continued)

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ATLANTIC POWER CORPORATION AND CAPITAL POWER INCOME L.P.

NOTES TO THE UNAUDITED PRO FORMA CONDENSED

COMBINED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5. Pro Forma Adjustments to Financial Statements (Continued)

 
  Six months ended
June 30, 2011
  Year ended
December 31, 2010
 

Atlantic Power's basic shares outstanding

    68,116     61,706  

Additional shares issued to CPILP unit holders

    31,500     31,500  

Additional shares on new equity issuance

    13,141     13,141  
           

Basic shares outstanding

    112,757     106,347  

Dilutive potential shares

             
 

Convertible debentures

    14,430     12,339  
 

LTIP notional units

    427     542  
           

Potentially dilutive shares

    127,614     119,228  

        Potentially dilutive shares from convertible debentures have been excluded from fully dilutive shares for the six months ended June 30, 2011 and for the year ended December 31, 2010 because their impact would be anti-dilutive.

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COMPARATIVE PER SHARE/UNIT MARKET PRICE DATA AND DIVIDEND INFORMATION

Selected Comparative Per Share/Unit Market Price and Dividend Information

        Atlantic Power common shares are listed and traded on the NYSE under the symbol "AT" and on the TSX under the symbol "ATP". CPILP units are listed and traded on the TSX under the symbol "CPA.UN". The following table sets forth, for the quarters indicated, the high and low sales price per share of Atlantic Power common shares as reported on both the NYSE and the TSX and the high and low sales price per unit of CPILP units as reported on the TSX. In addition, the table also sets forth the monthly cash dividends per share declared by Atlantic Power with respect to its common shares and monthly cash distributions per unit declared by CPILP with respect to its limited partnership units. On the Atlantic Power record date (                        , 2011), there were approximately                                    common shares of Atlantic Power outstanding. On the CPILP record date (                         , 2011), there were 56,597,899 CPILP units outstanding.

 
  Atlantic Power (TSX)   CPILP  
 
  High
(C$)
  Low
(C$)
  Dividends
Declared
  High   Low   Distributions
Declared
 

2009

                                     
 

First Quarter

  $ 9.28   $ 6.34     0.2735     18.98     12.90     0.63  
 

Second Quarter

    9.45     7.71     0.2735     16.21     11.65     0.44  
 

Third Quarter

    9.49     8.55     0.2735     16.30     13.62     0.44  
 

Fourth Quarter

    11.90     9.08     0.2735     15.77     13.35     0.44  

2010

                                     
 

First Quarter

    13.85     11.50     0.2735     18.43     15.54     0.44  
 

Second Quarter

    12.90     11.20     0.2735     18.14     15.05     0.44  
 

Third Quarter

    14.47     12.11     0.2735     18.85     16.03     0.44  
 

Fourth Quarter

    15.18     13.31     0.2735     19.02     17.11     0.44  

2011

                                     
 

First Quarter

    15.50     14.41     0.2735     21.22     17.65     0.44  
 

Second Quarter

    15.72     13.82     0.2735     21.05     18.28     0.44  
 

Third Quarter (until September 7, 2011)

    15.46     12.92     0.1824     19.50     17.23     0.44  

 

 
  Atlantic Power (NYSE)  
 
  High
($)
  Low
($)
  Dividends
Declared
 

2010

                   
 

Third Quarter (beginning July 23, 2010)

  $ 14.00   $ 12.10     0.266  
 

Fourth Quarter

    14.98     13.26     0.270  

2011

                   
 

First Quarter

    15.75     14.72     0.277  
 

Second Quarter

    16.18     14.33     0.28  
 

Third Quarter (until September 7, 2011)

    16.34     13.12     0.189  

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CERTAIN HISTORICAL AND PRO FORMA PER SHARE/UNIT DATA

        The following tables set forth certain historical, pro forma and pro forma equivalent per share financial information for Atlantic Power common shares and per unit financial information for CPILP units. The pro forma and pro forma equivalent per share/unit information gives effect to the Plan of Arrangement as if the Plan of Arrangement had occurred on June 30, 2011 in the case of book value per share data and as of January 1, 2010 in the case of net income per share/unit data.

        The pro forma per share balance sheet information combines CPILP's June 30, 2011 unaudited consolidated balance sheet with Atlantic Power's June 30, 2011 unaudited consolidated balance sheet. The pro forma per share income statement information for the fiscal year ended December 31, 2010, combines CPILP's audited consolidated statement of income for the fiscal year ended December 31, 2010, with Atlantic Power's audited consolidated statement of operations for the fiscal year ended December 31, 2010. The pro forma per share income statement information for the six months ended June 30, 2011, combines CPILP's unaudited consolidated statement of income for the six months ended June 30, 2011, with Atlantic Power's unaudited consolidated statement of operations for the six months ended June 30, 2011. The CPILP pro forma equivalent per share financial information is calculated by multiplying the unaudited Atlantic Power pro forma combined per share amounts by 1.3 (being the exchange ratio under the Plan of Arrangement). The balance sheet of CPILP as of June 30, 2011 has been translated using a C$/$ exchange rate of C$0.9643 to $1.00.

        The per share data for the Combined Company on a pro forma basis presented below is not necessarily indicative of the financial condition of the Combined Company had the Plan of Arrangement been completed on June 30, 2011 and the operating results that would have been achieved by the Combined Company had the Plan of Arrangement been completed as of the beginning of the period presented, and should not be construed as representative of the Combined Company's future financial condition or operating results. The per share data for the Combined Company on a pro forma basis presented below has been derived from the unaudited pro forma condensed combined consolidated financial data of the Combined Company included in this joint proxy statement. In addition, the unaudited pro forma information does not purport to indicate balance sheet data or results of operations data as of any future date or for any future period.

 
  As of and for the
Six Months Ended
June 30, 2011
  As of and for the
Year Ended
December 31, 2010
 

Atlantic Power Historical Data per Common Share

             
 

Income from continuing operations

             
   

Basic

  $ 0.28   $ (0.06 )
   

Diluted

  $ 0.28   $ (0.06 )
 

Dividends declared per Common Share

  $ 0.57   $ 1.06  
 

Book value per Common Share

  $ 6.33   $ 7.02  

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  As of and for the
Six Months Ended
June 30, 2011
  As of and for the
Year Ended
December 31, 2010
 

CPILP Historical Data per Unit(a)

             
 

Income from continuing operations attributable to controlling interest

             
   

Basic

  $ 0.19   $ 0.55  
   

Diluted

  $ 0.19   $ 0.55  
 

Distributions declared per unit

  $ 0.88   $ 1.76  
 

Book value per unit

  $ 5.87   $ 7.30  

(a)
Results for 2011 have been prepared using International Financial Reporting Standards.

 
  As of and for the
Six Months Ended
June 30, 2011
  As of and for the
Year Ended
December 31, 2010
 

Atlantic Power Pro Forma Combined Data per Common Share

             
 

Income from continuing operations

             
   

Basic

  $ 0.11   $ (0.02 )
   

Diluted

  $ 0.11   $ (0.02 )
 

Dividends declared per Common Share

  $ 0.58   $ 1.12  
 

Book value per Common Share

  $ 12.00   $ 13.28  

 

 
  As of and for the
Six Months Ended
June 30, 2011
  As of and for the
Year Ended
December 31, 2010
 

CPILP Pro Forma Equivalent Combined Data per unit

             
 

Income from continuing operations attributable to controlling interest

             
   

Basic

  $ 0.14   $ (0.03 )
   

Diluted

  $ 0.14   $ (0.03 )
 

Distributions declared per unit

  $ 0.75   $ 1.46  
 

Book value per unit

  $ 15.60   $ 17.26  

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COMPARISON OF RIGHTS OF ATLANTIC POWER
SHAREHOLDERS AND CPILP UNITHOLDERS

        If the Plan of Arrangement is completed, unitholders of CPILP may become shareholders of Atlantic Power. The rights of Atlantic Power shareholders are currently governed by the BCBCA and the articles of Atlantic Power. The rights of CPILP unitholders are currently governed by the Limited Partnerships Act (Ontario) ("LPA") and CPILP's partnership agreement.

        This section of the joint proxy statement describes the material differences between the rights of Atlantic Power shareholders and CPILP unitholders. This section does not include a complete description of all differences among the rights of Atlantic Power shareholders and CPILP unitholders, nor does it include a complete description of the specific rights of these persons.

        THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO, AND YOU ARE URGED TO READ CAREFULLY, THE RELEVANT PROVISIONS OF THE BCBCA, THE LPA AND THE ARTICLES OF ATLANTIC POWER AND THE LIMITED PARTNERSHIP AGREEMENT OF CPILP. THIS SUMMARY DOES NOT REFLECT ANY OF THE RULES OF THE NYSE OR TSX THAT MAY APPLY TO ATLANTIC POWER OR CPILP IN CONNECTION WITH THE PLAN OF ARRANGEMENT. A COPY OF THE ARTICLES OF ATLANTIC POWER IS FILED AS AN EXHIBIT TO THE REPORTS OF ATLANTIC POWER INCORPORATED BY REFERENCE IN THIS JOINT PROXY STATEMENT. SEE "WHERE YOU CAN FIND MORE INFORMATION" BEGINNING ON PAGE 150.

 
  Atlantic Power   CPILP

Outstanding Capital Stock:

  As of                    , 2011 there were common shares outstanding.   As of                    , 2011, CPILP had 56,597,899 issued and outstanding units.

Authorized Capital Stock:

 

Atlantic Power is authorized to issue an unlimited number of common shares.

 

CPILP is authorized to issue an unlimited number of units and an unlimited number of subscription receipts exchangeable into units. Any limited partner who holds units must not be a non-resident of Canada for purposes of the Tax Act. There are restrictions in the CPILP partnership agreement on unit ownership by non-residents of Canada.

Voting Rights:

 

On a poll, one vote per common share on all matters to be voted on at all meetings of shareholders. On a show of hands, one vote per person present.

 

Each limited partner is entitled to one vote per unit at all meetings of limited partners.

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  Atlantic Power   CPILP

Dividend Rights:

 

Holders of common shares are entitled to receive dividends as and when declared by the board of directors of Atlantic Power.

 

CPILP distributes cash to its limited partners on a monthly basis in accordance with the requirements of the CPILP partnership agreement and subject to the approval of the board of directors of the General Partner. Cash distributions are determined in consideration of cash amounts required for the operations of CPILP and the power plants including maintenance capital expenditures, debt repayments, and financing charges, and any cash retained at the discretion of the board of directors of the General Partner to satisfy anticipated obligations or to normalize monthly distributions. The cash distributions are made in respect of each calendar month to unitholders of record on the last day of each month commencing. Payments are made on or before the 30th day after each record date.

Restrictions on share transfers:

 

Transfers are governed by the Securities Transfer Act.

 

The limited partners have covenanted not to transfer their units to any person, including corporations or other entities, which has not represented, warranted and covenanted under the CPILP partnership agreement that it is not a non-resident of Canada for purposes of the Tax Act or, if a partnership, is a "Canadian Partnership" under the Tax Act.

Size of the Board of Directors:

 

The board of directors currently has six members. The BCBCA requires a public corporation to have at least three directors. Atlantic Power's articles provide for a minimum of three directors if the company is public, and no maximum of directors.

 

The board of directors of the general partner currently has eight members.

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  Atlantic Power   CPILP

Residency of Directors:

 

No residency requirement for directors.

 

Pursuant to the CBCA, at least 25% of the directors of the General Partner must be resident Canadians.

Election of Directors:

 

Election of directors may be made by shareholders at a shareholders' meeting where an existing director is removed, or otherwise by the shareholders or remaining directors in certain circumstances.

 

Unitholders do not have the right to elect directors of the general partner. CPI Investments elects the directors of the general partner. The CPILP partnership agreement requires that at least three directors be independent of Capital Power or its affiliates and EPCOR or its affiliates provided that combined such entities own at least 30% of the issued and outstanding Units. Should Capital Power and its affiliates and EPCOR and its affiliates not maintain a 30% ownership holding in CPILP (or such lower percentage, being not less than 20%, resulting from the issuance of Units other than to Capital Power and its affiliates or EPCOR and its affiliates), not less than four directors must be independent.

Removal of Directors:

 

A director may be removed by a resolution passed by a majority of the shareholders or may resign.

 

CPILP unitholders do not have the right to remove directors of the General Partner. CPI Investments, as the sole shareholder of the General Partner, may remove directors.

Filling of Vacancies on the Board of Directors:

 

The vacancy created by the removal of a director may be filled at the shareholder meeting at which he or she was removed. A vacancy not so filled at a shareholder meeting, or created by the resignation of a director, may be filled by a resolution of the remaining directors.

 

See "Election of Directors".

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  Atlantic Power   CPILP

Ability to call Special Meeting of Shareholders/Unitholders:

 

A requisition may be made by shareholders who, at the date on which the requisition is received by Atlantic Power, hold in the aggregate at least 1/20 of the issued shares of Atlantic that carry the right to vote at general meetings.

 

The general partner or limited partners holding not less than 10% of the outstanding units may request a meeting which shall be convened within 60 days of receipt of notice of the meeting. A quorum will consist of one or more limited partners present in person or by proxy holding at least 10% of the outstanding CPILP units.

Place of meetings:

 

The BCBCA provides that meetings may be held outside British Columbia if provided for in the articles or approved by shareholders or a resolution of directors.

 

All meetings are to be held in Calgary, Alberta or at other such place as the general partner or limited partners who have requested a meeting in accordance with the CPILP partnership agreement may designate.

Notice of Annual and Special Meetings of Shareholders/Unitholders:

 

Atlantic Power must send notice of the general meeting of the company at least 21 days but not more than two months before the meeting.

 

Notice of any meeting of limited partners is to be provided to each limited partner not less than 21 days prior to a meeting.

Shareholders/Unitholders Action by Written Consent:

 

A unanimous consent resolution of shareholders is deemed to be as valid and effective as if it had been passed at a meeting of shareholders.

 

Not specified.

Ability to set necessary levels of shareholder consent:

 

Articles can set levels for various shareholder approvals (other than those prescribed by the statute). The default threshold is a special resolution. The percentage of votes required for a special resolution can be specified in the articles, no less than 2/3 and no more than 3/4 of votes cast. Atlantic's articles provide that 2/3 of the votes cast on a given resolution will constitute a "special majority".

 

Not specified.

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  Atlantic Power   CPILP

Advance Notice Requirements for Proposals by Shareholders/Unitholders:

 

The proposal must be received at the registered office of Atlantic Power at least three months before the anniversary of the previous year's annual reference date.
The text of the proposal, the names and mailing addresses of the submitter and the supporters, and the text of the statement, if any, accompanying the proposal must be sent to all of the persons who are entitled to notice of the annual general meeting in relation to which the proposal is made in, or within the time set for the sending of, the notice of the applicable annual general meeting or) in Atlantic's information circular or equivalent, if any, sent in respect of the applicable annual general meeting.

 

Not specified.

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  Atlantic Power   CPILP

Directors' and Officers' Liability and Indemnification:

 

The BCBCA includes detailed provisions for permitted and prohibited indemnification of directors or officers. Gives discretion to the court to order payment or make any other order it considers appropriate.

Directors are not liable if they rely in good faith on financial statements, auditors' reports, professional reports, a statement of fact from an officer, or on other documents the court considers provide reasonable grounds for the directors' actions.

Atlantic Power has obtained a policy of insurance for the directors of Atlantic Power. Under the policy, Atlantic Power has reimbursement coverage to the extent that it has indemnified the directors. The policy includes securities claims coverage, insuring against any legal obligation to pay on account of any securities claims brought against the directors of Atlantic Power.

Atlantic Power has provided for indemnification of its directors from and against liability and costs in respect of any action or suit brought against them in connection with the execution of their duties of office, subject to certain limitations.

 

The LPA provides that where a corporation contravenes the act, any director or officer of such corporation, and where the corporation is an extra-provincial corporation, every person acting as its representative in Ontario, who authorized, permitted or acquiesced in such an offence is also guilty of an offence and on conviction is liable to a fine of not more than $2,000.

Oppression remedy:

 

The scope of potential claimants includes shareholders, beneficial owners of shares and any other person considered appropriate by the court. Claims may be based on conduct of the corporation that is oppressive or unfairly prejudicial.

 

No statutory right to bring oppression action.

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  Atlantic Power   CPILP

Derivative actions:

 

A shareholder, beneficial owner, director and any other person considered appropriate by the court may, with leave of the court, bring action in the name of the company or defend an action against the company. Shareholder approval of action is not determinative but will be taken into account.

 

No statutory right to bring derivative action.

Sale of all or substantially all the assets or undertaking of business:

 

The sale by a corporation of all or substantially all its undertaking, outside of the ordinary course of business, is permitted only if authorized by special resolution. Any such sale gives rise to dissent rights. The BCBCA exempts certain transactions with affiliates.

 

Extraordinary resolutions of the unitholders are required to approve the sale, exchange or other disposition of all or substantially all of the property of the Partnership, and the waiving of any default on the part of the general partner.

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SHAREHOLDER PROPOSALS

Atlantic Power

        Atlantic Power shareholder proposals intended to be presented at the next annual meeting of Atlantic Power shareholders and which are to be considered for inclusion in Atlantic Power's information circular and proxy statement and form of proxy for that meeting, must be received by Atlantic Power on or before January 18, 2012. These proposals must also comply with the rules of the SEC governing the form and content of proposals in order to be included in Atlantic Power's information circular and proxy statement and form of proxy. Any such proposals should be mailed to the Corporate Secretary at Atlantic Power Corporation, 200 Clarendon St., Floor 25, Boston, Massachusetts 02116.

        An Atlantic Power shareholder who wishes to present a proposal at the next annual meeting, other than a proposal to be considered for inclusion in Atlantic Power's information circular and proxy statement described above, must provide written notice of such proposal and appropriate supporting documentation to Atlantic Power no later than April 2, 2012. Proxies solicited by the Atlantic Power's board of directors will confer discretionary voting authority with respect to these proposals, subject to SEC rules governing the exercise of this authority. Any such proposal should be mailed the Corporate Secretary at Atlantic Power Corporation, 200 Clarendon St., Floor 25, Boston, Massachusetts 02116.


HOUSEHOLDING

Householding Information

        Atlantic Power has adopted a procedure approved by the SEC called "householding." Under this procedure, shareholders of record who have the same address and last name will receive only one copy of this proxy statement and accompanying Annual Report on Form 10-K and Quarterly Report on Form 10-Q, unless one or more of these shareholders notifies Atlantic Power that they wish to continue receiving individual copies. This procedure reduces Atlantic Power's printing costs and postage fees.

        Shareholders who participate in householding will continue to receive separate proxy cards. Also, householding will not in any way affect dividend check mailings.

        If you are eligible for householding, but you and other shareholders of record with whom you share an address currently receive multiple copies of our mailings and you wish to receive only a single copy of each of these documents for your household, please contact                                     .

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WHERE YOU CAN FIND MORE INFORMATION

        Atlantic Power files annual, quarterly and current reports, proxy statements and other information with the SEC under the Exchange Act, and Atlantic Power also files these documents with the securities regulatory authorities in each of the provinces and territories of Canada. You may read and copy any of this information at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room. The SEC also maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including Atlantic Power, who files electronically with the SEC. The address of that site is www.sec.gov. Atlantic Power also files its continuous and timely disclosure reports and other information on SEDAR at www.sedar.com. CPILP files its continuous and timely disclosure reports and other information on SEDAR.

        Investors may also consult Atlantic Power's and CPILP's website for more information about Atlantic Power or CPILP, respectively. Atlantic Power's website is www.atlanticpower.com. CPILP's website is www.capitalpowerincome.ca. Except as specifically incorporated by reference in this joint proxy statement, the information included on these websites is not incorporated by reference into this joint proxy statement.

        This joint proxy statement incorporates by reference the documents listed below that Atlantic Power has previously filed or will file with the SEC and with the Canadian securities regulators. These documents contain important information about Atlantic Power, its financial condition or other matters.

        If you are an Atlantic Power shareholder, copies of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 have been delivered to you along with this joint proxy statement. All shareholders and unitholders can obtain copies of any of these documents from the SEC, through the SEC's website at www.sec.gov or on SEDAR at www.sedar.com, or Atlantic Power will provide you with copies of these documents, without charge, upon written or oral request to: Atlantic Power Corporation, 200 Clarendon Street, Floor 25, Boston, Massachusetts 02116, telephone number (617) 977-2400.

        In the event of conflicting information in this joint proxy statement in comparison to any document incorporated by reference into this joint proxy statement, or among documents incorporated by reference, the information in the latest filed document controls.

        You should rely only on the information contained or incorporated by reference into this joint proxy statement. No one has been authorized to provide you with information that is different from that contained in, or incorporated by reference into, this joint proxy statement. This joint proxy statement is dated                        , 2011. You should not assume that the information contained in this joint proxy statement is accurate as of any date other than that date. You should not assume that the information incorporated by reference into this joint proxy statement is accurate as of any date other than the date of such incorporated document. Neither the mailing of this joint proxy statement to Atlantic Power shareholders or CPILP unitholders nor the issuance by Atlantic Power of common shares in connection with the Plan of Arrangement will create any implication to the contrary.

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CANADIAN SECURITIES LAW MATTERS

        

Legal Matters

        Certain Canadian legal matters relating to the Plan of Arrangement will be passed upon by Goodmans LLP on behalf of Atlantic Power. Certain United States legal matters relating to matters described in this joint proxy statement will be passed upon by Goodwin Procter LLP on behalf of Atlantic Power. Certain Canadian legal matters relating to the Plan of Arrangement are to be passed upon by Fraser Milner Casgrain LLP on behalf of CPI Investments and the General Partner, as general partner of CPILP, and by Norton Rose OR LLP on behalf of CPILP. Certain United States legal matters related to the Plan of Arrangement are to be passed by K&L Gates LLP on behalf of CPI Investments and the General Partner, as general partner of CPILP. As at the date hereof, the partners and associates of Fraser Milner Casgrain LLP beneficially owned, directly or indirectly, less than 1% of the outstanding CPILP units and less than 1% of the outstanding Atlantic Power common shares. As at the date hereof, the partners and associates of Norton Rose OR LLP beneficially owned, directly or indirectly, less than 1% of the outstanding CPILP units and less than 1% of the outstanding Atlantic Power common shares.


Experts

        The consolidated financial statements and financial statement schedule of Atlantic Power Corporation as of December 31, 2010 and 2009 and for each of the years in the three-year period ended December 31, 2010 appearing in Atlantic Power's Annual Report on Form 10-K (including the schedule appearing therein) have been incorporated by reference herein in reliance upon the reports of the United States and Canadian firms of KPMG LLP, independent registered public accounting firms, incorporated by reference herein, and upon the authority of said firms as experts in accounting and auditing.

        The consolidated financial statements of CPILP as of December 31, 2010, 2009 and 2008 and for each of the years in the three year period ended December 31, 2010 have been included in this joint proxy statement in reliance on the report of the Canadian firm of KPMG LLP, independent registered public accounting firm, and upon the authority of said firm as experts in auditing and accounting.


Information Filed on SEDAR

        Information has been incorporated by reference in this joint proxy statement from documents filed with the securities commissions or similar authorities in the provinces and territories of Canada. Copies of the documents incorporated in this joint proxy statement by reference may be obtained on request without charge from Atlantic Power, 200 Clarendon Street, 25th Floor, Boston, Massachusetts, U.S.A., 02116, telephone 617.977.2400, or the Corporate Secretary of CPI Income Services Ltd., the general partner of CPILP, at 10065 Jasper Avenue, Edmonton, Alberta T5J 3B1, telephone 780.392.5155. In addition, copies of the documents incorporated by reference herein may be obtained from the securities commissions or similar authorities in Canada through SEDAR at www.sedar.com. If you are an Atlantic Power shareholder, all documents required by United States securities laws to be delivered to you in full have been so delivered to you together with this joint proxy statement, including the complete annual and quarterly reports of both Atlantic Power and CPILP.

        The following documents filed with the securities commissions or similar authorities in the provinces and territories of Canada are specifically incorporated by reference into and form an integral part of this joint proxy statement:

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        Any statement contained in a document incorporated or deemed to be incorporated by reference in this joint proxy statement shall be deemed to be modified or superseded for the purposes of this joint proxy statement to the extent that a statement contained herein or in any other subsequently filed document which also is, or is deemed to be, incorporated by reference herein modifies or supersedes such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that was required to be stated or that was necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this joint proxy statement.

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Annex A

    Arrangement Agreement including,    

 

 

1.    Plan of Arrangement (Schedule A);

 

 

 

 

2.    Support Agreements (Schedule C);

 

 

 

 

3.    Distribution Agreement (Schedule F); and

 

 

 

 

4.    Preferred Share Guarantee Agreement (Schedule J).

 

 

Table of Contents

CAPITAL POWER INCOME L.P.
— and —
CPI INCOME SERVICES LTD.
— and —
CPI INVESTMENTS INC.
— and —
ATLANTIC POWER CORPORATION



ARRANGEMENT AGREEMENT



June 20, 2011

Annex A-1


Table of Contents


TABLE OF CONTENTS

ARTICLE 1 INTERPRETATION

  Annex A-5
 

1.1

 

Definitions

  Annex A-5
 

1.2

 

Interpretation Not Affected by Headings

  Annex A-21
 

1.3

 

Number and Gender

  Annex A-21
 

1.4

 

Date for Any Action

  Annex A-21
 

1.5

 

Statutory References

  Annex A-21
 

1.6

 

Currency

  Annex A-22
 

1.7

 

Accounting Matters

  Annex A-22
 

1.8

 

Rules of Construction

  Annex A-22
 

1.9

 

Consents and Approvals

  Annex A-22
 

1.10

 

Knowledge

  Annex A-22
 

1.11

 

Public Documents

  Annex A-22
 

1.12

 

Schedules

  Annex A-22

ARTICLE 2 THE ARRANGEMENT

 
Annex A-23
 

2.1

 

Plan of Arrangement

  Annex A-23
 

2.2

 

Implementation Steps by the Partnership Entities and the Corporation

  Annex A-23
 

2.3

 

Partnership Meeting

  Annex A-24
 

2.4

 

Interim Order

  Annex A-24
 

2.5

 

Final Order

  Annex A-25
 

2.6

 

Filing Articles of Arrangement and Effective Date

  Annex A-25
 

2.7

 

Payment of Consideration

  Annex A-25
 

2.8

 

Closing

  Annex A-26
 

2.9

 

Partnership Circular

  Annex A-26
 

2.10

 

Preparation of Filings

  Annex A-26
 

2.11

 

Court Proceedings

  Annex A-27
 

2.12

 

Public Communications

  Annex A-28
 

2.13

 

Outside Date

  Annex A-29
 

2.14

 

Meeting Coordination

  Annex A-29

ARTICLE 3 REPRESENTATIONS AND WARRANTIES

 
Annex A-29
 

3.1

 

Representations and Warranties of the Partnership and GP

  Annex A-29
 

3.2

 

Representations and Warranties of the Corporation

  Annex A-44
 

3.3

 

Representations and Warranties of the Purchaser

  Annex A-52
 

3.4

 

Disclosure Letters

  Annex A-65
 

3.5

 

Survival of Representations and Warranties

  Annex A-66

ARTICLE 4 COVENANTS

 
Annex A-66
 

4.1

 

Covenants of the Purchaser—General

  Annex A-66
 

4.2

 

Purchaser Meeting

  Annex A-67
 

4.3

 

Purchaser Circular; Form S-4

  Annex A-67
 

4.4

 

Preparation of Purchaser Filings

  Annex A-68
 

4.5

 

Conduct of Business by the Partnership

  Annex A-69
 

4.6

 

Conduct of Business by GP

  Annex A-72
 

4.7

 

Conduct of Business by the Corporation

  Annex A-75
 

4.8

 

Conduct of Business by the Purchaser

  Annex A-77
 

4.9

 

Mutual Covenants Regarding the Arrangement

  Annex A-78
 

4.10

 

Competition Act Approval, Investment Canada Act Approval and HSR Act Approval

  Annex A-80

Annex A-2


Table of Contents

 

4.11

 

Purchaser Financing

  Annex A-81
 

4.12

 

FPA Section 203 Approval

  Annex A-83
 

4.13

 

Covenants of the Partnership Entities Regarding Non-Solicitation

  Annex A-83
 

4.14

 

Covenants of the Corporation Regarding Non-Solicitation

  Annex A-87
 

4.15

 

Access to Information; Confidentiality

  Annex A-88
 

4.16

 

Insurance and Indemnification

  Annex A-88
 

4.17

 

Privacy Issues

  Annex A-89
 

4.18

 

Title Insurance

  Annex A-91
 

4.19

 

Notice and Cure Provisions

  Annex A-91
 

4.20

 

Pre-Acquisition Reorganization

  Annex A-91
 

4.21

 

Amendment of Constating Documents

  Annex A-92
 

4.22

 

Additional Covenants

  Annex A-92
 

4.23

 

Subsidiary Partnership Wind-Up

  Annex A-93
 

4.24

 

NC Purchase Agreement

  Annex A-94

ARTICLE 5 CONDITIONS PRECEDENT

 
Annex A-94
 

5.1

 

Mutual Conditions Precedent

  Annex A-94
 

5.2

 

Additional Conditions Precedent to the Obligations of the Partnership Entities

  Annex A-96
 

5.3

 

Additional Conditions Precedent to the Obligation of the Corporation

  Annex A-97
 

5.4

 

Additional Conditions Precedent to the Obligations of the Purchaser

  Annex A-98
 

5.5

 

Satisfaction of Conditions

  Annex A-100

ARTICLE 6 AMENDMENT AND TERMINATION

 
Annex A-100
 

6.1

 

Amendment

  Annex A-100
 

6.2

 

Term

  Annex A-100
 

6.3

 

Termination

  Annex A-100
 

6.4

 

Purchaser Termination Fee

  Annex A-102
 

6.5

 

Partnership Termination Fee

  Annex A-102
 

6.6

 

Expense Reimbursement

  Annex A-103
 

6.7

 

Liquidated Damages, Injunctive Relief and No Liability of Others

  Annex A-103

ARTICLE 7 GENERAL PROVISIONS

 
Annex A-103
 

7.1

 

Notices

  Annex A-103
 

7.2

 

Entire Agreement, Binding Effect and Assignment

  Annex A-106
 

7.3

 

Severability

  Annex A-106
 

7.4

 

No Third Party Beneficiaries

  Annex A-106
 

7.5

 

Time of Essence

  Annex A-106
 

7.6

 

Further Assurances

  Annex A-106
 

7.7

 

Remedies

  Annex A-106
 

7.8

 

Costs and Expenses

  Annex A-107
 

7.9

 

Governing Law

  Annex A-107
 

7.10

 

Notice of Limitation

  Annex A-107
 

7.11

 

Filing of Agreement

  Annex A-107
 

7.12

 

Waiver

  Annex A-107
 

7.13

 

Counterparts, Execution

  Annex A-107

Annex A-3


Table of Contents

Schedule A

 

 

Plan of Arrangement

Schedule B

 

 

Press Release

Schedule C

 

 

Partnership Support Agreements

Schedule D

 

 

Arrangement Resolution

Schedule E

 

 

List of CPC Agreements

Schedule F

 

 

Form of Distribution Agreement

Schedule G

 

 

Form of NC Purchase Agreement

Schedule H

 

 

List of Partnership Management Agreements

Schedule I

 

 

Term Sheet for Transitional Services Agreement

Schedule J

 

 

Forms of Preferred Share Guarantees

Annex A-4


Table of Contents


ARRANGEMENT AGREEMENT

        THIS AGREEMENT is made as of June 20, 2011.


AMONG:

        CAPITAL POWER INCOME L.P., a limited partnership established under the laws of the Province of Ontario;

(hereinafter, the "Partnership")


AND:

        CPI INCOME SERVICES LTD., a corporation incorporated under the Canada Business Corporations Act;

(hereinafter, "GP")


AND:

        CPI INVESTMENTS INC., a corporation incorporated under the Canada Business Corporations Act;

(hereinafter, the "Corporation")


AND:

        ATLANTIC POWER CORPORATION, a corporation continued under the Business Corporations Act (British Columbia);

(hereinafter, the "Purchaser")

        WHEREAS the Purchaser proposes to acquire, directly or indirectly, all of the issued and outstanding Partnership Units and Corporation Shares;

        WHEREAS the Parties intend to carry out the transactions contemplated herein by way of a plan of arrangement under the provisions of the CBCA;

        WHEREAS the parties intend that certain other transactions be completed in connection with the Arrangement, including those contemplated by the Partnership Reorganization Agreements;

        WHEREAS the Parties have entered into this Agreement to provide for the matters referred to in the foregoing recitals and for other matters relating to the Arrangement;

        NOW THEREFORE, in consideration of the covenants and agreements herein contained, the Parties hereby covenant and agree as follows:

ARTICLE 1
INTERPRETATION

1.1   Definitions

        In this Agreement (including the recitals, the Partnership Entity Disclosure Letter, the Corporation Disclosure Letter, the Purchaser Disclosure Letter and Schedules hereto), the following terms shall have the following meanings, and grammatical variations shall have the respective corresponding meanings:

        "Advance Ruling Certificate" means an advance ruling certificate issued by the Commissioner of Competition pursuant to section 102 of the Competition Act with respect to the transactions contemplated by this Agreement;

Annex A-5


Table of Contents

        "Affiliate" has the meaning ascribed thereto in the Securities Act and, for greater certainty, in the case of the Partnership, the Corporation and GP, shall not include Primary Energy Recycling Corporation or Primary Energy Recycling Holdings LLC and any of their Affiliates;

        "Agent" of a Person means any (i) director, officer, partner, member, consultant, manager or employee of that Person; (ii) advisor, law firm, accounting firm, engineering/environmental firm or other professional or consulting Person of or acting on behalf of that Person, or any lenders or underwriters to that Person; or (iii) any director, officer, partner, member, consultant or employee of any Agent referred to in clause (ii) of this definition;

        "Agreement" means this arrangement agreement, as the same may be amended, supplemented or otherwise modified in accordance with the terms hereof from time to time;

        "Arrangement" means an arrangement under section 192 of the CBCA on the terms and subject to the conditions set out herein and in the Plan of Arrangement as supplemented, modified or amended in accordance with the terms hereof or the Plan of Arrangement or at the direction of the Court in the Final Order;

        "Arrangement Resolution" means the extraordinary resolution of the Partnership Unitholders in respect of the Arrangement to be considered by the Partnership Unitholders at the Partnership Meeting, substantially in the form and content of Schedule D hereto;

        "Articles of Arrangement" means the articles of arrangement in respect of the Arrangement, required by the CBCA to be sent to the Director after the Final Order is made, which shall be in a form and content satisfactory to the Partnership, GP, the Corporation and the Purchaser, each acting reasonably;

        "Authorization" means any authorization, sanction, ruling, declaration, filing, order, permit, approval, grant, licence, waiver, entitlement, classification, exemption, registration, consent, right, notification, condition, franchise, privilege, certificate, judgment, writ, injunction, award, determination, direction, decision, decree, bylaw, rule or regulation of any Governmental Entity;

        "Benefit Plans" means any pension or retirement income, benefit, supplemental benefit, stock option, restricted stock, stock appreciation right, restricted stock unit, phantom stock or other equity-based compensation plan, deferred compensation, severance, health, welfare, medical, dental, disability plans or any other employee compensation or benefit plans, policies, programs or other arrangements and all related agreements and policies with third parties such as trustees or insurance companies, which are maintained by a Party or any of its Subsidiaries with respect to any of their current or former employees, directors, officers or other individuals providing services to such Party or any of its Subsidiaries including, without limitation, "plans" as defined in Section 3(3) of ERISA;

        "Bridge Loans" has the meaning ascribed in Section 4.11(a)(i);

        "Business Day" means any day other than a Saturday, Sunday or a statutory or civic holiday in the Province of Alberta or Ontario or the State of Massachusetts or New York;

        "CBCA" means the Canada Business Corporations Act, R.S.C. 1985, c. C-44, as amended, and the regulations made thereunder;

        "Certificate of Arrangement" means the certificate to be issued by the Director pursuant to subsection 192(7) of the CBCA giving effect to the Arrangement;

        "CFR" means the U.S. Code of Federal Regulations;

        "Class A Consideration" has the meaning ascribed in Section 2.1(b);

        "Class A Corporation Shares" means the Class A Shares in the capital of the Corporation;

        "Class B Consideration" has the meaning ascribed in Section 2.1(c);

Annex A-6


Table of Contents

        "Class B Corporation Shares" means the Class B Shares in the capital of the Corporation;

        "Code" means the U.S. Internal Revenue Code of 1986, as amended;

        "Commissioner of Competition" means the Commissioner of Competition appointed pursuant to the Competition Act or a person designated or authorized pursuant to the Competition Act to exercise the powers and perform the duties of the Commissioner of Competition;

        "Commitment Letter" has the meaning ascribed in Section 3.3(w);

        "Competition Act" means the Competition Act (Canada), R.S.C. 1985, c. C-34, as amended, and the regulations thereunder;

        "Competition Act Approval" means:

and, in the case of (b) or (c), the Purchaser has been advised in writing by the Commissioner of Competition that, in effect, such person does not have sufficient grounds at that time to apply to the Competition Tribunal under section 92 of the Competition Act with respect to the transactions contemplated by this Agreement and therefore the Commissioner of Competition, at that time, does not intend to make an application under section 92 of the Competition Act in respect of the transactions contemplated by this Agreement, and any terms and conditions attached to any such advice are acceptable to the Purchaser, acting reasonably, and such advice has not been rescinded or amended prior to the Effective Time;

        "Competition Filing" has the meaning ascribed in Section 4.10(a);

        "Confidentiality Agreement" means, collectively, the confidentiality agreement dated October 25, 2010 among the Partnership, CPRPSLP and the Purchaser, and the Confidentiality Agreement dated May 6, 2011 among the Purchaser, the Partnership, CPRPSLP and CPC;

        "Consents" means those consents and approvals required from, and notices required to, any third party to proceed with the transactions contemplated by this Agreement, the Partnership Reorganization Agreements and the Plan of Arrangement;

        "Contract" means any contract, agreement, license, franchise, arrangement, joint venture, partnership, lease, commitment, understanding or other right or obligation (written or oral) to which a Party or any of its Subsidiaries is a party or by which a Party or any of its Subsidiaries is bound or affected or to which any of their respective properties or assets is subject;

        "Corporation Acquisition Proposal" means a proposal or offer, oral or written, relating to any of the following (other than the transactions contemplated by this Agreement or the Arrangement): (i) any merger, amalgamation, arrangement, share exchange, take-over bid, tender offer, recapitalization, consolidation, other business combination, liquidation or winding up directly or indirectly involving the Corporation, (ii) any sale or acquisition of beneficial ownership of any of the Corporation Shares, or (iii) any sale or acquisition of any Partnership Units owned by the Corporation

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or any exchange, mortgage, pledge, granting of any right or option to acquire or other arrangement involving the Partnership Units owned by the Corporation having similar economic effect;

        "Corporation Board" means the board of directors of the Corporation;

        "Corporation Consents" means the Consents set forth in Schedule 3.2(b) to the Corporation Disclosure Letter;

        "Corporation Disclosure Letter" means the disclosure letter executed by the Corporation and delivered to the Purchaser concurrently with the execution and delivery of this Agreement;

        "Corporation Financial Statements" means the unaudited financial statements of the Corporation as at and for the year ended December 31, 2010, and as at and for the three month period ended March 31, 2011 in the Data Site;

        "Corporation Material Contracts" means all Contracts to which the Corporation is a party or by which it is bound: (i) which, if terminated, modified or if ceased to be in effect without the consent of the Corporation, would have, or would reasonably be expected to have, a Material Adverse Effect in respect of the Corporation; (ii) under which the Corporation directly or indirectly guarantees any liabilities or obligations of a third party; (iii) providing for the establishment, investment in, organization or formation of any joint ventures or partnerships or for the acquisition of any shares or securities of any Person (other than the Partnership Agreement); (iv) which limits or restricts the Corporation from engaging in any line of business or in any geographic area in any material respect; (v) with CPC or any Affiliate thereof that is controlled by CPC; (vi) which are indentures, credit agreements, security agreements, mortgages, promissory notes and other contracts relating to indebtedness for borrowed money, whether incurred, assumed, guaranteed or secured by any asset; (vii) under which the Corporation is obligated to make or expects to receive payments in excess of $100,000 over the remaining term of the Contract; or (viii) that is otherwise material to the Corporation;

        "Corporation Regulatory Approvals" means those Regulatory Approvals set forth in Schedule 3.2(c) to the Corporation Disclosure Letter;

        "Corporation Shareholders" means holders of Corporation Shares, being EPCOR and CPLP;

        "Corporation Shares" means collectively, the Class A Corporation Shares and the Class B Corporation Shares;

        "Court" means the Court of Queen's Bench of Alberta;

        "CPC" means Capital Power Corporation, a corporation incorporated under the Canada Business Corporations Act;

        "CPC Agreements" means those Contracts set forth in Schedule E attached hereto;

        "CPEL" means CPI Preferred Equity Ltd., a corporation incorporated under the Business Corporations Act (Alberta);

        "CPEL Preferred Shares" means, collectively, the Cumulative Redeemable Preferred Shares, Series 1, the Cumulative Rate Reset Preferred Shares, Series 2 and the Cumulative Floating Rate Preferred Shares, Series 3, each issued by CPEL;

        "CPEL Public Documents" means all documents and information filed by CPEL under applicable Securities Laws on SEDAR since January 1, 2011 and accessible to the public on the SEDAR website as of the date hereof;

        "CPIH" means CPI Power Holdings Inc., a corporation incorporated under the laws of the State of Delaware;

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        "CPLP" means Capital Power L.P., a limited partnership established under the laws of the Province of Ontario;

        "CPRPSLP" means CP Regional Power Services Limited Partnership, a limited partnership established under the laws of the Province of Alberta;

        "CRA" means the Canada Revenue Agency;

        "Data Site" means the electronic data room established and maintained by the Partnership at https://fmc.firmex.com in the form and content available as of 9:00 p.m. (Mountain time) on the date immediately preceding the date hereof;

        "Depositary" means Computershare Investor Services Inc.;

        "Director" means the Director or a Deputy Director appointed pursuant to section 260 of the CBCA;

        "Distribution Agreement" means the distribution agreement to be entered into at the Effective Time among, CPIH, New LLC, CPEL, the Partnership and the Purchaser in the form set forth in Schedule F hereto;

        "Effective Date" means the date shown on the Certificate of Arrangement, which date shall be determined in accordance with Section 2.6;

        "Effective Time" has the meaning ascribed thereto in the Plan of Arrangement;

        "Eligible Holder" means CPLP and any Partnership Unitholder, other than a Person that is exempt from tax under Part I of the Tax Act, and includes a partnership that is a Partnership Unitholder if one or more of its partners would, if directly a Partnership Unitholder, otherwise be an Eligible Holder;

        "Employee Hiring Agreement" means the agreement dated the date hereof among CPC, Capital Power Operations (USA) Inc. and the Purchaser providing for the transfer of employees to the Purchaser (or such Person or Persons as are designated by the Purchaser);

        "Encumbrances" means any pledges, liens, charges, security interests, leases, title retention agreements, mortgages, hypothecs, statutory or deemed trusts, adverse rights or claims, easements, indentures, deeds of trust, rights of way, restrictions on use of real property, licences to third parties, leases to third parties, security agreements, assignments, or encumbrances of any kind or character whatsoever, whether contingent or absolute, and any agreement, option, right of first refusal, right or privilege (whether by Law, contract or otherwise) capable of becoming any of the foregoing;

        "Environmental Laws" means all material Laws relating to pollution or protection of human health and safety, the environment (including, without limitation, ambient air, surface water, groundwater, land surface or subsurface strata) or wildlife, including, without limitation, Laws relating to the discharge, release or spill or threatened discharge, release or spill of Hazardous Substances or to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of Hazardous Substances;

        "Environmental Reports" means collectively, the Phase 1 environmental reports for each of the Partnership Facilities in the Data Site;

        "EPCOR" means EPCOR Utilities Inc., a corporation incorporated under the Business Corporations Act (Alberta);

        "ERISA" means the U.S. Employee Retirement Income Security Act of 1974, as amended;

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        "ERISA Affiliate" means any entity that is treated as a trade or business under common control and a single employer with a Person pursuant to 29 CFR Section 4001.3 and the definition of "Employer" in 29 CFR Section 4001.2;

        "Exchanges" means the TSX and the NYSE;

        "Exempt Wholesale Generator" has the meaning ascribed thereto in Section 1262(6) of PUHCA;

        "FERC" means the Federal Energy Regulatory Commission;

        "Final Order" means the final order of the Court approving the Arrangement to be applied for by the Partnership, GP and the Corporation following the Partnership Meeting and to be granted pursuant to subsection 192(4) of the CBCA in respect of the Partnership, GP and the Corporation, as such order may be affirmed, amended or modified by the Court (with the consent of each of the Partnership, GP, the Corporation and the Purchaser, each acting reasonably) at any time prior to the Effective Date or, if appealed, then, unless such appeal is withdrawn or denied, as affirmed or as amended (provided that such amendment is acceptable to each of the Partnership, GP, the Corporation and the Purchaser, each acting reasonably) on appeal;

        "Foreign Utility Company" has the meaning ascribed thereto in Section 1262(6) of PUHCA and the regulations set forth in 18 CFR § 366.1;

        "Form S-4" means a registration statement on Form S-4 (or other applicable form) pursuant to which the Purchaser shall seek to register the Purchaser Share Issuance under the U.S. Securities Act;

        "FPA" means the Federal Power Act;

        "FPA Section 203 Approval" has the meaning referenced in Section 4.12;

        "FPA Section 203 Filing" has the meaning ascribed in Section 4.12;

        "GAAP" means the generally accepted accounting principles and practices in Canada, including the principles set forth in the Handbook published by the Canadian Institute of Charter Accountants, or any successor institute, which are applicable as at the date of the financial information in respect of which a calculation is made hereunder or as at the date of the particular financial statements referred to herein, as the case may be;

        "Governmental Entity" means any applicable (i) multinational, federal, provincial, state, regional, municipal, local or other government, governmental or public department, ministry, central bank, court, tribunal, arbitral body, commission, commissioner, board, bureau or agency, domestic or foreign, (ii) stock exchange, including each of the Exchanges; (iii) subdivision, agent, or authority of any of the foregoing, or (iv) quasi-governmental or private body, including any tribunal, commission, regulatory agency or self-regulatory organization, exercising any regulatory, expropriation or taxing authority under or for the account of any of the foregoing;

        "GP" means CPI Income Services Ltd., and, for greater certainty, except where otherwise contemplated, means CPI Income Services Ltd. in its personal capacity and not as general partner of the Partnership;

        "GP Board" means the board of directors of GP;

        "GP Financial Statements" means the unaudited financial statements of the GP as at and for the year ended December 31, 2010, and as at and for the three month period ended March 31, 2011 in the Data Site;

        "GP Material Contracts" means all Contracts to which GP is a party or by which it is bound: (i) which, if terminated or modified or if it ceased to be in effect, would have, or would reasonably be expected to have, a Material Adverse Effect in respect of GP; (ii) under which GP directly or indirectly guarantees any liabilities or obligations of a third party; (iii) providing for the establishment, investment

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in, organization or formation of any joint ventures or partnerships or for the acquisition of any shares or securities of any Person (other than the Partnership Agreement); (iv) which limits or restricts GP from engaging in any line of business or in any geographic area in any material respect; (v) with CPC or any Affiliate thereof that is controlled by CPC; (vi) which are indentures, credit agreements, security agreements, mortgages, promissory notes and other contracts relating to indebtedness for borrowed money, whether incurred, assumed, guaranteed or secured by any asset; (vii) under which GP is obligated to make or expects to receive payments in excess of $100,000 over the remaining term of the Contract; or (viii) that is otherwise material to GP;

        "Hazardous Substances" means chemicals, pollutants, contaminants, wastes, residual materials, toxic substances, deleterious substances or hazardous substances, including petroleum or petroleum products;

        "HSR Act" means Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;

        "HSR Act Approval" means the expiration or termination of any waiting period under the HSR Act;

        "IFRS" means the International Financial Reporting Standards as issued by the International Accounting Standards Board and adopted by the Canadian Institute of Chartered Accountants;

        "Intellectual Property" means all intellectual property existing, used or currently being developed for use and all rights therein, including all claims for past infringement, worldwide, whether registered or unregistered, including without limitation: (a) all patents, patent applications and other patent rights, used, including divisional and continuation patents; (b) all registered and unregistered trade-marks, service marks, logos, slogans, corporate names, business names, and other indicia of origin, and all applications and registrations therefor, (c) registered and unregistered copyrights and mask works, including all copyright in and to computer software programs, including software, and applications and registration of such copyright; (d) internet domain names, applications and reservations for internet domain names, uniform resource locators and the corresponding Internet sites; (e) industrial designs, (f) trade secrets and proprietary information not otherwise listed in (a) through (e) above, including, without limitation, all inventions (whether or not patentable), invention disclosures, moral and economic rights of authors and inventors (however denominated), confidential information, technical data, customer lists, corporate and business names, trade names, trade dress, brand names, know-how, show-how, mask works, formulae, methods (whether or not patentable), designs, processes, procedures, technology, business methods, source codes, object codes, computer software programs (in either source code or object code form) databases, data collections and other proprietary information or material of any type, and all derivatives, improvements and refinements thereof, howsoever recorded, or unrecorded; and (g) any goodwill associated with any of the foregoing;

        "Interim Order" means the interim order of the Court concerning the Arrangement under subsection 192(4) of the CBCA in respect of the Partnership, GP and the Corporation, containing declarations and directions with respect to the Arrangement and the holding of the Partnership Meeting, as such order may be affirmed, amended or modified by any court of competent jurisdiction with the consent of the Partnership Entities, the Corporation and the Purchaser, each acting reasonably;

        "Investment Canada Act" means the Investment Canada Act, R.S.C. 1985, c. 28 (1st Supp.) as amended and the regulations promulgated thereunder;

        "Investment Canada Act Approval" means the Minister under the Investment Canada Act (the "Minister") shall have sent a notice pursuant to subsection 21(1), subsection 22(2) or paragraph 23(3)(a) of that Act to the Purchaser, on terms and conditions satisfactory to the Purchaser, acting reasonably, stating that the Minister is satisfied that the transactions contemplated by the Agreement are likely to be of net benefit to Canada, or alternatively, the relevant time period provided

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for such notice under section 21 or section 22 of the Investment Canada Act shall have expired such that the Minister shall be deemed, pursuant to subsection 21(9) or subsection 22(4) of the Investment Canada Act, to be satisfied that the transactions contemplated by the Agreement are of net benefit to Canada;

        "Investment Canada Filing" has the meaning ascribed in Section 4.10(b);

        "Key Regulatory Approvals" means, collectively, Competition Act Approval, Investment Canada Act Approval, HSR Act Approval, and the FPA Section 203 Approval;

        "Law" or "Laws" means all laws, statutes, codes, ordinances, decrees, rules, regulations, bylaws, statutory rules, judicial or arbitral or administrative or ministerial or departmental or regulatory judgments, orders, decisions, rulings, injunctions, determinations, awards or other requirements, and terms and conditions of any permit, grant of approval, permission, authority or licence of any Governmental Entity, statutory body or self-regulatory authority (including the Exchanges), and the term "applicable" with respect to such Laws and in the context that refers to one or more Persons, means that such Laws apply to such Person or Persons and/or its Subsidiaries or its or their business, undertaking, property, Benefit Plans or securities and emanate from a Governmental Entity having jurisdiction over the Person or Persons and/or its Subsidiaries or its or their business, undertaking or securities;

        "Management Agreement Assignment Agreement" means the agreement dated the date hereof among Capital Power Operations (USA) Inc., Frederickson Power L.P., and the Purchaser providing for the assignment of the operations and maintenance agreement made effective April 29, 2004 among Capital Power Operations (USA) Inc. (as successor by merger to Frederickson Project Operations Inc.), Frederickson Power L.P. and Puget Sound Energy, Inc. to the Purchaser (or such person as is designated by the Purchaser) immediately following the completion of the Plan of Arrangement;

        "Management Agreements Termination Agreement" means the agreement dated the date hereof among CP Regional Power Services Limited Partnership, Capital Power Operations (USA) Inc. and the Partnership, CPI Power (Williams Lake) Ltd., Manchief Power Company LLC, Curtis/Palmer Hydroelectric Company, LP, CPI USA Holdings LLC and CPI USA Ventures LLC providing for the termination of the Partnership Management Agreements (other than the operations and maintenance agreement made effective April 29, 2004 among Capital Power Operations (USA) Inc. (as successor by merger to Frederickson Project Operations Inc.), Frederickson Power L.P. and Puget Sound Energy, Inc.) immediately following the completion of the Plan of Arrangement;

        "Market-Based Rate Authorization" means authorization granted by FERC to a Partnership Subsidiary pursuant to Section 205 of the FPA to sell wholesale electric energy, capacity or certain ancillary services at rates established in accordance with market conditions, acceptance of a tariff by FERC providing for such sales, and issuance of an order by FERC providing for such authorization and tariff acceptance, and granting such regulatory waivers and blanket authorizations to such Partnership Subsidiary as are customarily granted by FERC to companies authorized to sell electricity at market-based rates, including blanket authorization to issue securities and assume liabilities pursuant to Section 204 of the FPA;

        "Material Adverse Effect" means, with respect to any Person(s), any change, effect, event, occurrence, fact, state of facts or development that, either individually is or in the aggregate are, or individually or in the aggregate would reasonably be expected to be, both material and adverse to the business, operations, results of operations, properties, assets, liabilities, obligations (whether accrued, conditional or otherwise) or condition (financial or otherwise) of such Person(s) and its Subsidiaries taken as a whole, other than any change, effect, event, occurrence, fact, state of facts or development:

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provided, however, that the change, effect, event, occurrence or state of facts or development referred to in clauses (a) to (e) above shall not be excluded from the definition of Material Adverse Effect in respect of any Person if it materially disproportionately adversely affects such Person and its Subsidiaries, taken as a whole, compared to other companies of similar size operating in the industry in which the Person and its Subsidiaries operate;

        "Material Change" has the meaning ascribed thereto in the Securities Act;

        "Material Fact" has the meaning ascribed thereto in the Securities Act;

        "misrepresentation" has the meaning ascribed thereto in the Securities Act;

        "MI 61-101" means Multilateral Instrument 61-101—Protection of Minority Security Holders in Special Transactions;

        "NC LLC" means CPI USA North Carolina LLC, a limited liability company formed under the laws of the State of Delaware;

        "NC Purchase Agreement" means the membership interest purchase agreement dated the date hereof between CPI USA Holdings LLC, CPIH and Capital Power Investments LLC in the form set forth in Schedule G hereto;

        "NERC" means the North American Electric Reliability Corporation;

        "New LLC" has the meaning ascribed to it in Section 4.24(c);

        "New LLC2" has the meaning ascribed to it in Section 4.24(c);

        "NYSE" means the New York Stock Exchange;

        "Outside Date" means, subject to Section 2.13, February 29, 2012 or such later date as may be mutually agreed to in writing by the Parties;

        "Parties" means, collectively, the Partnership, GP, the Corporation and the Purchaser, and "Party" means either of them;

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        "Partnership Acquisition Proposal" means a proposal or offer, oral or written, relating to any of the following (other than the transactions contemplated by this Agreement or the Arrangement): (i) any take-over bid (including an acquisition of Partnership Units from the Corporation), tender offer or exchange offer that, if consummated, would result in any Person, or group of Persons or shareholders of such Person(s) beneficially owning 20% or more of any class of voting or equity securities of the Partnership; (ii) a plan of arrangement, merger, amalgamation, consolidation, share exchange, business combination, reorganization, recapitalization, liquidation, dissolution or other similar transaction involving the Partnership and/or the Partnership Subsidiaries whose assets or revenues, individually or in the aggregate, constitute 20% or more of the consolidated assets or revenues, as applicable, of the Partnership; (iii) any sale or acquisition, direct or indirect, of assets representing 20% or more of the consolidated assets or revenues of the Partnership or which contribute 20% or more of the consolidated revenues of the Partnership, or any lease, long-term supply agreement (other than in the ordinary course of business), exchange, mortgage, pledge or other arrangement having a similar economic effect, in a single transaction or a series of related transactions; or (iv) any sale or acquisition of beneficial ownership of 20% or more of the Partnership Units (or securities convertible or exchangeable into voting or equity securities of the Partnership) or 20% or more of the voting or equity securities of any of the Partnership Subsidiaries (or securities convertible or exchangeable into voting or equity securities of such Partnership Subsidiaries) whose assets, individually or in the aggregate, constitute 20% or more of the consolidated assets or revenues of the Partnership or which contribute 20% or more of the consolidated assets or revenues of the Partnership, or rights or interests therein or thereto in a single transaction or a series of related transactions;

        "Partnership Agreement" means the amended and restated limited partnership agreement of the Partnership made effective as of November 4, 2009;

        "Partnership Annual Financial Statements" means the audited consolidated financial statements of the Partnership as at and for the years ended December 31, 2010 and 2009, together with the notes thereto and the auditors' report thereon;

        "Partnership Circular" means the notice of meeting and management information circular, including all schedules, appendices and exhibits thereto, to be prepared and mailed to the Partnership Unitholders in connection with the Partnership Meeting, as may be amended, supplemented or otherwise modified;

        "Partnership Entities" means the Partnership and GP;

        "Partnership Entity Consents" means the Consents set forth in Schedule 3.1(c) to the Partnership Entity Disclosure Letter;

        "Partnership Entity Disclosure Letter" means the disclosure letter executed by the Partnership Entities and delivered to the Purchaser concurrently with the execution and delivery of this Agreement;

        "Partnership Entity Regulatory Approvals" means those Regulatory Approvals set forth in Schedule 3.1(c) to the Partnership Entity Disclosure Letter;

        "Partnership Facilities" means the facilities in which the Partnership holds a direct or indirect interest, except for (i) the Partnership's Roxboro and Southport facilities located in the State of North Carolina, and (ii) any facilities owned, directly or indirectly, by PERH;

        "Partnership Fairness Opinions" means the opinions of CIBC World Markets Inc. and Greenhill & Co. Canada Ltd., the financial advisors to the Partnership, to the effect that, as of the date of each such opinion, subject to the assumptions and limitations set out therein, the Partnership Unitholder Consideration to be received by the Partnership Unitholders (other than the Purchaser, the Corporation and GP) in connection with the transactions contemplated by this Agreement is fair, from a financial point of view, to such Partnership Unitholders;

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        "Partnership Financial Statements" means, collectively, the Partnership Annual Financial Statements and the Partnership Interim Financial Statements;

        "Partnership Interim Financial Statements" means the unaudited consolidated financial statements of the Partnership for the three month periods ended March 31, 2011 and 2010, together with the notes thereto;

        "Partnership Management Agreements" means those Contracts listed in Schedule H attached hereto;

        "Partnership Material Contracts" means all Contracts to which the Partnership or any of the Partnership Subsidiaries is a party or by which any of them is bound: (i) which provide for aggregate future payments by or to any of them in excess of $10 million in any 12-month period; (ii) which, if terminated, modified or if ceased to be in effect without the consent of the Partnership or any of the Partnership Subsidiaries, would have, or would reasonably be expected to have, a Material Adverse Effect in respect of the Partnership; (iii) under which the Partnership or any of the Partnership Subsidiaries directly or indirectly guarantees any liabilities or obligations of a third party in excess of $10 million in the aggregate; (iv) providing for the establishment, investment in, organization or formation of any joint ventures or partnerships or for the acquisition of any shares or securities of any Person (other than a Partnership Subsidiary); (v) which limits or restricts the Partnership or any Partnership Subsidiary from engaging in any line of business or in any geographic area in any material respect; (vi) with CPC or any Affiliate thereof (other than with the Partnership or any Partnership Subsidiary) that is controlled by CPC; (vii) which are indentures, credit agreements, security agreements, mortgages, promissory notes and other contracts relating to indebtedness for borrowed money, whether incurred, assumed, guaranteed or secured by any asset; (viii) which are PPAs, (ix) which are "material contracts" within the meaning of applicable Securities Laws; (x) under which a Partnership Facility procures 25% or more of its current fuel supply; (xi) any lease of a Partnership Facility; or (xii) that is otherwise material to the Partnership and its subsidiaries, considered as a whole;

        "Partnership Meeting" means the special meeting of Partnership Unitholders, including any adjournment or postponement thereof, to be held to consider the Arrangement Resolution;

        "Partnership Public Documents" means all documents and information filed by the Partnership under applicable Securities Laws on SEDAR since January 1, 2011 and accessible to the public on the SEDAR website as of the date hereof;

        "Partnership Reorganization Agreements" means the NC Purchase Agreement and the Distribution Agreement;

        "Partnership Subsidiaries" means all Subsidiaries of the Partnership, and which, for the purposes of this Agreement, shall not include NC LLC, New LLC, New LLC2, PERH or any Subsidiary of PERH;

        "Partnership Support Agreements" means the support agreements dated the date hereof between the Purchaser and each of EPCOR, CPLP and CPC, which have been duly executed and delivered by the parties thereto in the forms set forth in Schedule C;

        "Partnership Termination Fee" has the meaning ascribed thereto in Section 6.5;

        "Partnership Unitholder Approval" has the meaning ascribed thereto in Section 2.4(b);

        "Partnership Unitholders" means holders of Partnership Units;

        "Partnership Units" means the limited partnership units of the Partnership;

        "Partnership Unitholder Consideration" has the meaning ascribed thereto in Section 2.1(a);

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        "Pension Transfer Agreement" means the agreement dated the date hereof entered into among the Purchaser, CPC and Capital Power Operations (USA) Inc. providing for certain pension matters;

        "PERC" means Primary Energy Recycling Corporation;

        "PERC Agreements" means, together, (a) the amended and restated management agreement made as of August 24, 2009 among CPI USA Ventures LLC (as successor to EPCOR USA Ventures LLC), PERC, PERH, and Primary Energy Operations LLC and (b) the amended and restated securityholders' agreement made as of August 24, 2009 among CPI USA Ventures LLC (as successor to EPCOR USA Ventures LLC), EPCOR USA Holdings LLC, PERC and PERH, and any amendments or other modifications thereto;

        "PERH" means Primary Energy Recycling Holdings LLC;

        "Permitted Encumbrances" means (a)(i) liens for taxes, assessments and governmental charges or levies not yet due and payable and for which appropriate provision has been made in accordance with GAAP, U.S. GAAP or IFRS, as the case may be, and (ii) encumbrances such as materialmen's, mechanics', carriers', workmen's and repairmen's liens and other similar liens arising in the ordinary course of business (but excluding those not discharged in the ordinary course of business); (b) access agreements, servitudes, easements and rights of way relating to sewers, water lines, gas lines, pipelines, electric lines, telephone and cable lines, and other similar services or products; (c) zoning restrictions and other limitations imposed by any Governmental Entity having jurisdiction over real property; (d) reservations in federal patents; (e) as to properties comprising any portion of the facilities in which such Person(s) conducts its business which are leased, or otherwise held by contractual interest, the terms and conditions of the leases and other contracts pertaining thereto that have been provided to the Purchaser prior to the date of this Agreement; (f) customary rights of general application reserved to or vested in any Governmental Entity to control or regulate any interest in the facilities in which such Person(s) conducts its business; provided that such liens, encumbrances, exceptions, agreements, restrictions, limitations, contracts and rights (i) were not incurred in connection with any indebtedness and (ii) do not, individually or in the aggregate, have a material adverse effect on the value or materially impair or add material cost to the use of the subject property; and (g) the terms of the Partnership Material Contracts, the PERC Agreements, the Corporation Material Contracts and the Purchaser Material Contracts;

        "Person" includes an individual, limited or general partnership, limited liability company, limited liability partnership, trust, joint venture, association, body corporate, unincorporated organization, trustee, executor, administrator, legal representative, government (including any Governmental Entity) or any other entity, whether or not having legal status;

        "Plan of Arrangement" means the plan of arrangement, substantially in the form and content of Schedule A attached hereto as such plan of arrangement may be amended or supplemented from time to time in accordance with the terms thereof and hereof;

        "Pre-Acquisition Reorganization" has the meaning ascribed thereto in Section 4.20;

        "Preferred Share Guarantees" means the guarantees of the Purchaser in respect of the preferred share obligations of CPEL, forms of which are set forth in Schedule J hereto to be effective immediately following completion of the Plan of Arrangement;

        "PPAs" means power purchase agreements, energy supply agreements, electricity supply agreements, renewable energy supply agreements or electric power tolling agreements for power projects;

        "Proposed Agreement" has the meaning ascribed thereto in Section 4.13(e);

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        "PUHCA" means the Public Utility Holding Company Act of 2005, enacted as part of the Energy Policy Act of 2005, Pub. L. No. 109-58, as codified at 42 U.S.C. § 16451, et seq., together with the regulations promulgated thereunder;

        "Purchaser Acquisition Proposal" means a proposal or offer, oral or written, relating to any of the following (other than the transactions contemplated by this Agreement or the Arrangement): (i) any take-over bid, tender offer or exchange offer that, if consummated, would result in any Person, or group of Persons or shareholders of such Person(s) beneficially owning 20% or more of any class of voting or equity securities of the Purchaser; (ii) a plan of arrangement, merger, amalgamation, consolidation, share exchange, business combination, reorganization, recapitalization, liquidation, dissolution or other similar transaction involving the Purchaser and/or the Purchaser Subsidiaries whose assets or revenues, individually or in the aggregate, constitute 20% or more of the consolidated assets or revenues, as applicable, of the Purchaser; (iii) any sale or acquisition, direct or indirect, of assets representing 20% or more of the consolidated assets or revenues of the Purchaser or which contribute 20% or more of the consolidated revenues of the Purchaser, or any lease, long-term supply agreement (other than in the ordinary course of business), exchange, mortgage, pledge or other arrangement having a similar economic effect, in a single transaction or a series of related transactions; or (iv) any sale or acquisition of beneficial ownership of 20% or more of the Purchaser Shares (or securities convertible or exchangeable into voting or equity securities of the Purchaser) or a majority of the voting or equity securities of any of the Purchaser Subsidiaries (or securities convertible or exchangeable into voting or equity securities of such Purchaser Subsidiaries) whose assets, individually or in the aggregate, constitute 20% or more of the consolidated assets or revenues of the Purchaser or which contribute 20% or more of the consolidated assets or revenues of the Purchaser, or rights or interests therein or thereto in a single transaction or a series of related transactions;

        "Purchaser Annual Financial Statements" means the audited consolidated financial statements of the Purchaser as at and for the years ended December 31, 2010 and 2009, together with the notes thereto and the auditors' report thereon;

        "Purchaser Board" means the board of directors of the Purchaser;

        "Purchaser Circular" means the notice of meeting and management information circular, including all schedules, appendices and exhibits thereto, to be prepared and mailed to the Purchaser Shareholders in connection with the Purchaser Meeting, as may be amended, supplemented or otherwise modified;

        "Purchaser Consents" means the Consents set forth in Schedule 3.3(b) to the Purchaser Disclosure Letter;

        "Purchaser Data Site" means the electronic data room established and maintained by the Purchaser at https://services.intralinks.com/ui/flex/CIX.html?workspaceId=816445&defa ultTab=documents the form and content available as of 9:00 p.m. (Mountain time) on the date immediately preceding the date hereof;

        "Purchaser Disclosure Letter" means the disclosure letter executed by the Purchaser and delivered to the Partnership and the Corporation concurrently with the execution and delivery of this Agreement;

        "Purchaser Financial Statements" means, collectively, the Purchaser Annual Financial Statements and the Purchaser Interim Financial Statements;

        "Purchaser Interim Financial Statements" means the unaudited consolidated financial statements of Purchaser for the three month periods ended on March 31, 2011 and 2010, together with the notes thereto;

        "Purchaser Material Contracts" means all Contracts to which the Purchaser or any of the Purchaser Subsidiaries is a party or by which any of them is bound: (i) which provide for aggregate

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future payments by the Purchaser or any Purchaser Material Subsidiary in excess of $10 million in any 12-month period; (ii) which, if terminated, modified or if ceased to be in effect without the consent of the Purchaser or any of the Purchaser Subsidiaries, would have, or would reasonably be expected to have, a Material Adverse Effect in respect of the Purchaser; (iii) under which the Purchaser or any of the Purchaser Material Subsidiaries directly or indirectly guarantees any liabilities or obligations of a third party in excess of $10 million in the aggregate; (iv) providing for the establishment, investment in, organization or formation of any joint ventures or partnerships (other than with a wholly owned Purchaser Subsidiary) or for the acquisition of any shares or securities of any Person (other than a Purchaser Subsidiary); (v) which limits or restricts the Purchaser or any Purchaser Material Subsidiary from engaging in any line of business or in any geographic area in any material respect; (vi) which are indentures, credit agreements, security agreements, mortgages, promissory notes and other contracts relating to indebtedness for borrowed money, (vii) which are PPAs; or (viii) which are "material contracts" within the meaning of applicable Securities Laws;

        "Purchaser Material Subsidiaries" means Pasco Cogen, Ltd., Atlantic Path 15, LLC, Lake Cogen Ltd., Auburndale Power Partners, L.P. and Chambers Cogeneration Limited Partnership, Cadillac Renewable Energy, LLC, Idaho Wind Partners 1, LLC, Orlando Cogen Limited, L.P., Piedmont Green Power, LLC, Gregory Power Partners, L.P., Gregory Partners, LLC, Auburndale GP LLC and Epsilon Power Partners, LLC;

        "Purchaser Meeting" means the special meeting of Purchaser Shareholders, including any adjournment or postponement thereof, to consider the Purchaser Share Issuance Resolution;

        "Purchaser Note" means the non-interest bearing promissory note to be issued by the Purchaser in favour of CPLP in the principal amount of $121,405,211 as part of the Plan of Arrangement;

        "Purchaser Opinions" means the opinions dated the date hereof to the Purchaser Board from TD Securities Inc. and Morgan Stanley & Co. LLC;

        "Purchaser Public Documents" means all documents and information filed by the Purchaser under applicable Securities Laws on SEDAR or EDGAR since January 1, 2011 and accessible to the public on the SEDAR or EDGAR as of the date hereof;

        "Purchaser Regulatory Approvals" means those Regulatory Approvals set forth in Schedule 3.3(c) to the Purchaser Disclosure Letter;

        "Purchaser Share Issuance" means the issuance of Purchaser Shares pursuant to the Arrangement;

        "Purchaser Share Issuance Resolution" means the ordinary resolution approving the issuance of the Purchaser Shares pursuant to the Arrangement, in accordance with the requirements of the Exchanges, to be considered by the Purchaser Shareholders at the Purchaser Meeting;

        "Purchaser Shareholders" means the holders of the Purchaser Shares;

        "Purchaser Shares" means the common shares in the capital of the Purchaser;

        "Purchaser Subsidiaries" means all Subsidiaries of the Purchaser and Idaho Wind Partners 1, LLC, including the Purchaser Material Subsidiaries;

        "Purchaser Termination Fee" has the meaning ascribed thereto in Section 6.4;

        "PURPA" means the Public Utility Regulatory Policies Act of 1978;

        "Qualifying Facility" means a "Qualifying Facility" as defined by Section 201 of PURPA and the rules set forth in 18 CFR Part 292;

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        "Regulatory Approvals" means authorizations, sanctions, rulings, consents, orders, exemptions, permits, declarations and other approvals (including the lapse, without objection, of a prescribed time under a statute or regulation that states that a transaction may be implemented if a prescribed time lapses following the giving of notice without an objection being made) of, or filings with, or notices to, Governmental Entities, including the Key Regulatory Approvals;

        "ROFL Termination Agreement" means the agreement to be entered into on the Effective Date between CPC and the Partnership providing for the termination of the existing rights of the first look held by the Partnership;

        "SEC" means the United States Securities and Exchange Commission;

        "Securities Act" means the Securities Act (Alberta) and the rules, regulations and published policies made thereunder;

        "Securities Authorities" means the securities commissions or similar regulatory authorities in each of the provinces and territories of Canada, and the SEC;

        "Securities Laws" means the Securities Act, together with all other applicable Canadian securities laws, rules and regulations and published policies thereunder, the U.S. Securities Act and the U.S. Exchange Act, together with the rules and regulations promulgated thereunder, and listing standards of the TSX and the NYSE;

        "Securities Offerings" has the meaning ascribed in Section 4.11(a)(ii);

        "Subsidiary" has the meaning ascribed thereto in National Instrument 45-106—Prospectus and Registration Exemptions;

        "Superior Proposal" means, with respect to the Partnership, any bona fide written Partnership Acquisition Proposal made by a third party that was not solicited by or on behalf of the Partnership after the date hereof, and that the GP Board, determines in good faith (after receipt of advice from its financial advisors and outside legal counsel) (i) is reasonably capable of being completed without undue delay, taking into account all legal, financial, regulatory and other aspects of such Partnership Acquisition Proposal and the party making such Partnership Acquisition Proposal; (ii) in respect of which any required financing to complete such Partnership Acquisition Proposal is committed or has been demonstrated to the satisfaction of the GP Board is reasonably available; (iii) which is available to all Partnership Unitholders on the same terms and conditions; (iv) which is not subject a due diligence and/or access condition (provided, however, that it may have been subject to such a condition which has been satisfied or irrevocably waived); (v) that did not result from a breach of Section 4.13 or 4.14; and (vi) which would, taking into account all of the terms and conditions of such Partnership Acquisition Proposal, if consummated in accordance with its terms (but not assuming away any risk of non-completion), result in a transaction more favourable to the Partnership Unitholders, from a financial point of view, than the Arrangement (including any adjustment to the terms and conditions of the Arrangement proposed by the Purchaser pursuant to Section 4.13(f)); provided that, for purposes of this definition, "Partnership Acquisition Proposal" shall have the meaning set forth above, except that the references in the definition thereof to "20% or more of the securities" shall be deemed to be references to "all of the securities" and references to "20% or more of the consolidated assets or revenues" shall be deemed to be references to "all of the consolidated assets or revenues"; provided, however, that any such transaction may involve the Partnership with or without the Partnership's facilities in North Carolina or the entity that holds such assets and may involve a separate party purchasing any such assets;

        "Tax Act" means the Income Tax Act (Canada) and the regulations made thereunder, as amended;

        "Tax" or "Taxes" means all federal, state, provincial, territorial, county, municipal, local or foreign taxes, duties, imposts, levies, assessments, tariffs and other charges imposed, assessed or collected by a

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Governmental Entity including (i) any gross income, net income, gross receipts, business, royalty, capital, capital gains, goods and services, value added, severance, stamp, franchise, occupation, premium, capital stock, sales and use, real property, land transfer, personal property, ad valorem, transfer, licence, profits, windfall profits, environmental, payroll, employment, employer health, pension plan, anti-dumping, countervail, excise, severance, stamp, occupation, or premium tax, (ii) all withholdings for taxes on amounts paid to or by the relevant person, (iii) all employment insurance premiums, Canada, and any other pension plan contributions or premiums and worker's compensation premiums and contributions, (iv) any fine, penalty, interest, or addition to tax, (v) any tax imposed, assessed, or collected or payable pursuant to any tax-sharing agreement or any other contract relating to the sharing or payment of any such tax, levy, assessment, tariff, duty, deficiency, or fee, and (vi) any liability for any of the foregoing as a transferee, successor, guarantor, or by contract or by operation of Law;

        "Tax Returns" means all reports, forms, elections, designations, schedules, statements, estimates, declarations of estimated Tax, information statements and returns required to be filed, or in fact filed, with a Governmental Entity with respect to Taxes;

        "Transitional Services Agreement" means the agreement to be entered into as of the Effective Time among CPRPSLP, Capital Power Operations (USA) Inc. and the Purchaser providing for the provision to the Purchaser and its Subsidiaries of certain transitional services for certain periods of time following the Effective Time, reflecting the terms set forth in Schedule I hereto;

        "TSX" means the Toronto Stock Exchange;

        "U.S. Exchange Act" means the United States Securities Exchange Act of 1934, as amended;

        "U.S. GAAP" means accounting principles generally accepted in the United States of America; and

        "U.S. Securities Act" means the United States Securities Act of 1933, as amended.

1.2   Interpretation Not Affected by Headings

        The division of this Agreement into Articles, Sections, Paragraphs and Schedules and the insertion of a table of contents and headings are for convenience of reference only and do not affect the construction or interpretation of this Agreement. The terms "hereof", "hereunder", "herein" and similar expressions refer to this Agreement and not to any particular Article, Section, Paragraph, Schedule or other portion hereof. Unless something in the subject matter or context is inconsistent therewith, references herein to Articles, Sections, Paragraphs and Schedules are to Articles, Sections and Paragraphs of, and Schedules to, this Agreement.

1.3   Number and Gender

        In this Agreement, words importing the singular number include the plural and vice versa, and words importing any gender include all genders.

1.4   Date for Any Action

        If the date on which any action is required to be taken hereunder by a Party is not a Business Day, such action shall be required to be taken on the next succeeding day which is a Business Day.

1.5   Statutory References

        In this Agreement, unless something in the subject matter or context is inconsistent therewith or unless otherwise herein provided, a reference to any statute is to that statute as now enacted or as the same may from time to time be amended, re-enacted or replaced and includes any regulations made thereunder.

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1.6   Currency

        Unless otherwise stated, all references in this Agreement to sums of money are expressed in lawful money of Canada and "$" refers to Canadian dollars.

1.7   Accounting Matters

        Unless otherwise stated, all accounting terms used in this Agreement shall have the meanings attributable thereto under GAAP and all determinations of an accounting nature required to be made shall be made in a manner consistent with GAAP.

1.8   Rules of Construction

        The Parties hereto acknowledge that their respective legal counsel have reviewed and participated in settling the terms of this Agreement, and the Parties agree that any rule of construction to the effect that any ambiguity is to be resolved against the drafting party will not be applicable to the interpretation of this Agreement.

1.9   Consents and Approvals

        Any requirement in this Agreement for a Party to consent to or approve of an action taken or proposed to be taken by the other Party, or for a Party to be satisfied as to certain matters (including the conditions to closing contained herein), and any similar phrases, shall require the consent, approval or satisfaction of the GP Board in the case of the Partnership Entities.

1.10 Knowledge

        In this Agreement, references to "the knowledge of the Partnership" or to "the knowledge of the Partnership Entities" means the actual knowledge (and not constructive or imputed knowledge), in their capacity as officers of the GP, of each of Stuart Anthony Lee, Anthony Scozzafava and B. Kathryn Chisholm of the GP, after due inquiry, and references to "the knowledge of the Purchaser" means the actual knowledge (and not constructive or imputed knowledge), in their capacity as officers of the Purchaser, of each of Barry Welch and Paul Rapisarda, after due inquiry, and references to "the knowledge of the Corporation" means the actual knowledge (and not constructive or imputed knowledge), in their capacity as officers of the Corporation, of each of Stuart Anthony Lee and B. Kathryn Chisholm of the Corporation, after due inquiry.

1.11 Public Documents

        To the extent any of the representations and warranties contained in Article 3 are qualified by Partnership Public Documents or Purchaser Public Documents, such public documents shall be deemed to: (i) exclude any exhibits and schedules thereto, disclosures in the "Risk Factors" or "Forward Looking Statements" sections thereof or any other disclosure included in such documents that is cautionary, predictive or forward looking in nature; and (ii) only include those matters included therein solely to the extent that it is reasonably apparent from a reading of such disclosure that it is applicable to the matters referenced in such Section of Article 3.

1.12 Schedules

        The following Schedules are attached to this Agreement and are incorporated by reference into this Agreement and form a part hereof:

Schedule A

 

—    Plan of Arrangement

Schedule B

 

—    Press Release

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Schedule C

 

—    Partnership Support Agreements

Schedule D

 

—    Arrangement Resolution

Schedule E

 

—    List of CPC Agreements

Schedule F

 

—    Form of Distribution Agreement

Schedule G

 

—    Form of NC Purchase Agreement

Schedule H

 

—    List of Partnership Management Agreements

Schedule I

 

—    Term Sheet for Transitional Services Agreement

Schedule J

 

—    Forms of Preferred Share Guarantees

ARTICLE 2
THE ARRANGEMENT

2.1   Plan of Arrangement

        As soon as reasonably practicable following the date hereof, and on the terms and subject to the conditions set forth herein and in the Plan of Arrangement, the Partnership Entities, the Corporation and the Purchaser shall proceed to effect the Arrangement by way of a plan of arrangement under section 192 of the CBCA and in respect of which, on the terms and subject to the conditions contained herein and in the Plan of Arrangement:

2.2   Implementation Steps by the Partnership Entities and the Corporation

        Each of the Partnership Entities and the Corporation covenants in favour of the Purchaser that it shall, jointly with the others:

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2.3   Partnership Meeting

        Subject to the terms of this Agreement and receipt of the Interim Order, each of the Partnership Entities agrees and covenants in favour of the Purchaser that it shall:

2.4   Interim Order

        The application referred to in Section 2.2(a) shall request that the Interim Order provide, among other things:

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2.5   Final Order

        If (a) the Interim Order is obtained, and (b) the Arrangement Resolution is passed at the Partnership Meeting by the Partnership Unitholders as provided for in the Interim Order and as required by applicable Law, the Partnership Entities shall as soon as reasonably practicable thereafter and in any event within two Business Days thereafter take all steps necessary or reasonably desirable to submit the Arrangement to the Court and diligently pursue an application for the Final Order pursuant to section 192 of the CBCA.

2.6   Filing Articles of Arrangement and Effective Date

        No later than the third Business Day after the satisfaction or waiver (subject to applicable Laws) of the conditions (excluding conditions that, by their terms, cannot be satisfied until the Effective Date, but subject to the satisfaction or, where permitted, waiver of those conditions as of the Effective Date) set forth in Article 5, the Articles of Arrangement shall be filed by the Partnership Entities with the Director. From and after the Effective Time, the Plan of Arrangement will have all of the effects provided by applicable Law, including the CBCA. The Parties shall use their reasonable best efforts to cause the Effective Date to occur on or about December 15, 2011 or as soon thereafter as reasonably practicable and in any event by the Outside Date.

2.7   Payment of Consideration

        The Purchaser will, following receipt of the Final Order and prior to the filing by the Partnership Entities and the Corporation of the Articles of Arrangement with the Director, in accordance with the Plan of Arrangement, deliver or cause to be delivered to the Depositary on or prior to the Effective Date (a) sufficient funds to satisfy the cash consideration payable to the Partnership Unitholders and the Corporation Shareholders, pursuant to the Plan of Arrangement; and (b) sufficient Purchaser Shares to satisfy the Purchaser share consideration payable to the Partnership Unitholders and Corporation Shareholders, pursuant to the Plan of Arrangement.

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2.8   Closing

        The completion of the transactions contemplated hereby and by the Arrangement will take place at the Calgary office of Fraser Milner Casgrain LLP, 15th Floor, Bankers Court, 850—2nd Street S.W., Calgary, AB T2P 0R8 at 8:00 a.m. (Mountain time) on the Effective Date, or such other time and place as may be agreed to by the Parties.

2.9   Partnership Circular

        Subject to compliance with Section 2.10, as soon as reasonably practicable after the execution and delivery of this Agreement, the Partnership Entities shall prepare the Partnership Circular together with any other documents required by the Securities Laws or other applicable Laws in connection with the Partnership Meeting to be filed and prepared by the Partnership Entities. Subject to Section 2.3(a) and Section 2.10, as soon as reasonably practicable after the execution and delivery of this Agreement, the Partnership Entities shall, unless otherwise agreed by the Partnership Entities and the Purchaser, cause the Partnership Circular and such other documentation required in connection with the Partnership Meeting to be mailed to the Partnership Unitholders and filed in all jurisdictions where the same is required to be filed as required by the Interim Order and applicable Laws. The Partnership Circular shall include the unanimous recommendation of the GP Board that the Partnership Unitholders vote in favour of the Arrangement Resolution, subject to the terms of this Agreement, and a statement that each director and executive officer of each of the Partnership Entities intends to vote all of his or her Partnership Units in favour of the Arrangement Resolution, and shall include a copy of the Partnership Fairness Opinions.

2.10 Preparation of Filings

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2.11 Court Proceedings

        Each of the Partnership Entities and the Corporation will provide the Purchaser and its legal counsel with reasonable opportunity to review and comment upon drafts of all material to be filed with

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the Court in connection with the Arrangement, including by providing on a timely basis a description of any information required to be supplied by the Purchaser for inclusion in such material, prior to the service and filing of that material, and will give reasonable consideration to all such comments of the Purchaser and its legal counsel. Each of the Partnership Entities and the Corporation will ensure that all material filed with the Court in connection with the Arrangement is consistent in all material respects with the terms of this Agreement, the agreements that it contemplates and the Plan of Arrangement. In addition, each of the Partnership Entities and the Corporation agree that it will not object to legal counsel to the Purchaser making submissions on behalf of the Purchaser on the application (and the hearing of the motion) for the Interim Order and the application (and the hearing of the motion) for the Final Order as such counsel considers appropriate, provided that the Partnership Entities and the Corporation are advised of the nature of any submissions prior to the hearing and such submissions are consistent with this Agreement, the agreements that it contemplates and the Plan of Arrangement. Each of the Partnership Entities and the Corporation will also provide to legal counsel to the Purchaser on a timely basis copies of any notice and evidence served on it or its legal counsel in respect of the application for the Interim Order or the Final Order or any appeal therefrom. Subject to applicable Law, none of the Partnership Entities and the Corporation will file any material with the Court in connection with the Arrangement or serve any such material, and will not agree to modify or amend materials so filed or served, except as contemplated hereby or with the Purchaser's prior written consent, such consent not to be unreasonably withheld, conditioned or delayed; provided that nothing herein shall require the Purchaser to agree or consent to any increase in the consideration contemplated in connection with the Arrangement or other modification or amendment to such filed or served materials that expands or increases the Purchaser's obligations set forth in any such filed or served materials or under this Agreement or the Arrangement. The Partnership Entities and the Corporation shall also provide to the Purchaser's outside counsel on a timely basis copies of any notice of appearance or other Court documents served on any of the Partnership Entities and/or the Corporation in respect of the application for the Interim Order or the Final Order or any appeal therefrom and of any notice, whether written or oral, received by any of the Partnership Entities and/or the Corporation indicating any intention to oppose the granting of the Interim Order or the Final Order or to appeal the Interim Order or the Final Order. Each of the Partnership Entities and the Corporation will also oppose any proposal from any party that the Final Order contain any provision inconsistent with this Arrangement Agreement, and, if at any time after the issuance of the Final Order and prior to the Effective Date, any of the Partnership Entities and/or the Corporation is required by the terms of the Final Order or by Law to return to Court with respect to the Final Order, it shall do so after notice to, and in consultation and cooperation with, the Purchaser.

2.12 Public Communications

        The Parties agree to issue jointly a press release with respect to this Agreement and the Arrangement in the form set forth in Schedule B attached hereto promptly after its due execution. The Partnership Entities, the Corporation and the Purchaser agree to co-operate in the preparation of presentations, if any, to the Partnership Unitholders, the Purchaser Shareholders, investors, analysts and ratings agencies regarding the Arrangement prior to the making of such presentations and to advise, consult and cooperate with each other in issuing any press releases or otherwise making public statements with respect to this Agreement or the Arrangement. Each of the Partnership Entities, the Corporation and the Purchaser shall use all reasonable commercial efforts to enable the other Party to review and comment on all such press releases and disclosure prior to the release thereof; provided, however, that the foregoing shall be subject to each Party's overriding obligation to make disclosure or filing required under applicable Laws, and if such disclosure is required and the other Party has not reviewed or commented on the disclosure, the Party making such disclosure shall use reasonable commercial efforts to give prior oral or written notice to the other Party, and if such prior notice is not possible, to give such notice immediately following the making of such disclosure.

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2.13 Outside Date

        The Parties covenant and agree that any Party may postpone the Outside Date for up to 30 days (in 10-day increments) if the consummation of the transactions contemplated hereby is delayed by (i) any appealable judgment rendered by a court of competent jurisdiction enforceable against the Partnership Entities, the Corporation or the Purchaser, (ii) the Parties not having obtained any Regulatory Approval that was not denied by a non-appealable decision of a Governmental Entity, or (iii) the Parties not having obtained any Consent required to be obtained hereunder, by giving written notice to the other Parties to such effect no later than 5:00 p.m. (Mountain time) on the date that is not less than five days prior to the original Outside Date (and any subsequent Outside Date); provided that such judgment is being appealed or such Regulatory Approval or Consent is being actively sought, as applicable.

2.14 Meeting Coordination

        The Partnership Entities and the Purchaser agree to use their commercially reasonable efforts to schedule the Partnership Meeting and the Purchaser Meeting on the same day, provided that the Purchaser Meeting shall be scheduled to occur prior to the Partnership Meeting.

ARTICLE 3
REPRESENTATIONS AND WARRANTIES

3.1   Representations and Warranties of the Partnership and GP

        The Partnership and GP hereby jointly and severally represent and warrant to and in favour of the Purchaser as follows and acknowledge that the Purchaser is relying upon such representations and warranties in connection with the entering into of this Agreement:

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3.2   Representations and Warranties of the Corporation

        The Corporation hereby represents and warrants to and in favour of the Purchaser as follows and acknowledges that the Purchaser is relying upon such representations and warranties in connection with the entering into of this Agreement:

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3.3   Representations and Warranties of the Purchaser

        The Purchaser hereby represents and warrants to and in favour of each of the Partnership and the Corporation as follows and acknowledges that each of the Partnership and the Corporation is relying upon such representations and warranties in connection with the entering into of this Agreement:

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3.4   Disclosure Letters

        Concurrently with the execution and delivery of this Agreement, the Partnership Entities are delivering to the Purchaser the Partnership Entity Disclosure Letter and the Corporation is delivering to the Purchaser the Corporation Disclosure Letter, each of which is deemed to modify the representations and the warranties of the Partnership Entities and the Corporation, respectively, contained in this Agreement, and the Purchaser is delivering to each of the Partnership Entities and the Corporation the Purchaser Disclosure Letter, which is deemed to modify the representations and warranties of the Purchaser contained in this Agreement. Notwithstanding anything in the Partnership Entity Disclosure Letter, the Corporation Disclosure Letter or the Purchaser Disclosure Letter to the contrary, all disclosures in the Partnership Entity Disclosure Letter, the Corporation Disclosure Letter and the Purchaser Disclosure Letter must reference or be associated with a particular Section in this Agreement, but will also be interpreted to relate to or modify other Sections of this Agreement. The inclusion of any item in the Partnership Entity Disclosure Letter, the Corporation Disclosure Letter or the Purchaser Disclosure Letter shall not be construed as an admission by the Partnership Entities, the Corporation or the Purchaser, as applicable, of the materiality of such item.

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3.5   Survival of Representations and Warranties

ARTICLE 4
COVENANTS

4.1   Covenants of the Purchaser—General

        The Purchaser covenants and agrees with the Partnership Entities and the Corporation that, from the date of this Agreement until the earlier of the Effective Time and the time this Agreement is terminated in accordance with its terms, except with the prior written consent of the Partnership Entities and the Corporation (such consent not to be unreasonably withheld of delayed), and except as otherwise expressly permitted or specifically contemplated by this Agreement (including the Plan of Arrangement) or required by applicable Laws:

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4.2   Purchaser Meeting

        Subject to the terms of this Agreement, the Purchaser covenants in favour of the Partnership Entities and the Corporation that it shall:

4.3   Purchaser Circular; Form S-4

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4.4   Preparation of Purchaser Filings

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4.5   Conduct of Business by the Partnership

        The Partnership Entities covenant and agree with the Purchaser that they shall, and shall cause the Partnership Subsidiaries to, during the period from the date of this Agreement until the earlier of the Effective Time and the time that this Agreement is terminated in accordance with its terms, unless the Purchaser shall otherwise agree in writing (such agreement not to be unreasonably withheld or delayed), and except in each case as otherwise permitted or contemplated by this Agreement, the Partnership Reorganization Agreements, the Management Agreements Termination Agreement, the Management Agreement Assignment Agreement or the Plan of Arrangement, as contemplated in Schedule 4.5 to the Partnership Entity Disclosure Letter, or as is otherwise required by applicable Law, conduct its and their respective businesses only in, and not take any action except in, the ordinary course of business, use all reasonable commercial efforts to maintain and preserve its and their business

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organization and goodwill, assets, employees and advantageous business relationships, and, without limiting the generality of the foregoing, not:

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        In addition, the Partnership Entities covenant and agree with the Purchaser that they shall, and shall cause the Partnership Subsidiaries to, during the period from the date of this Agreement until the earlier of the Effective Time and the time that this Agreement is terminated in accordance with its terms, use its reasonable commercial efforts (taking into account insurance market conditions and offerings and industry practices) to cause their current insurance policies, including directors' and officers' insurance, not to be cancelled or terminated or any of the coverages thereunder to lapse, except where such cancellation, termination or lapse would not individually or in the aggregate be material to the Partnership, unless simultaneously with such termination, cancellation or lapse, replacement policies underwritten by insurance or re-insurance companies of nationally recognized standing having comparable deductibles and providing coverage equal to or greater than the coverage under the cancelled, terminated or lapsed policies for substantially similar premiums are in full force and effect; provided that subject to Section 4.16, none of the Partnership Entities or any Partnership Subsidiary shall obtain or renew any insurance (or re-insurance) policy for a term exceeding 12 months from the date hereof.

4.6   Conduct of Business by GP

        GP covenants and agrees with the Purchaser that it shall, during the period from the date of this Agreement until the earlier of the Effective Time and the time that this Agreement is terminated in accordance with its terms, unless the Purchaser shall otherwise agree in writing (such agreement not to be unreasonably withheld or delayed), cause the Partnership to comply with its obligations under this Agreement and the Plan of Arrangement, and except as otherwise expressly permitted or specifically contemplated by this Agreement or the Plan of Arrangement, as contemplated in Schedule 4.6 of the Partnership Entity Disclosure Letter, or as is otherwise required by applicable Law, conduct its business only in, and not take any action except in, the ordinary course of business, use all reasonable

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commercial efforts to maintain and preserve its business organization, assets, employees and advantageous business relationships, and, without limiting the generality of the foregoing, not:

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        In addition, GP covenants and agrees with the Purchaser that it shall vote, or cause to be voted, the Partnership Units owned by it in favour of the Arrangement at the Partnership Meeting, and that it shall, during the period from the date of this Agreement until the earlier of the Effective Time and the time that this Agreement is terminated in accordance with its terms, use its reasonable commercial efforts (taking into account insurance market conditions and offerings and industry practices) to cause its current insurance policies, including directors' and officers' insurance, not to be cancelled or

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terminated or any of the coverages thereunder to lapse, except where such cancellation, termination or lapse would not individually or in the aggregate be material to GP, unless simultaneously with such termination, cancellation or lapse, replacement policies underwritten by insurance or re-insurance companies of nationally recognized standing having comparable deductibles and providing coverage equal to or greater than the coverage under the cancelled, terminated or lapsed policies for substantially similar premiums are in full force and effect; provided that subject to Section 4.16, the GP shall not obtain or renew any insurance (or re-insurance) policy for a term exceeding 12 months from the date hereof.

4.7   Conduct of Business by the Corporation

        The Corporation covenants and agrees with the Purchaser that it shall, during the period from the date of this Agreement until the earlier of the Effective Time and the time that this Agreement is terminated in accordance with its terms, unless the Purchaser shall otherwise agree in writing (such agreement not to be unreasonably withheld or delayed), and except as otherwise expressly permitted or specifically contemplated by this Agreement or the Plan of Arrangement, as contemplated by the Corporation Disclosure Letter, or as is otherwise required by applicable Law, conduct its business only in, and not take any action except in, the ordinary course of business, use all reasonable best efforts to maintain and preserve its business organization, assets, employees and advantageous business relationships, and, without limiting the generality of the foregoing, not:

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        In addition, the Corporation covenants and agrees with the Purchaser that it shall vote, or cause to be voted, the Partnership Units owned by it in favour of the Arrangement at the Partnership Meeting, and that it shall, during the period from the date of this Agreement until the earlier of the Effective

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Time and the time that this Agreement is terminated in accordance with its terms, use its reasonable commercial efforts (taking into account insurance market conditions and offerings and industry practices) to cause its current insurance policies, including directors' and officers' insurance, not to be cancelled or terminated or any of the coverages thereunder to lapse, except where such cancellation, termination or lapse would not individually or in the aggregate be material to the Corporation, unless simultaneously with such termination, cancellation or lapse, replacement policies underwritten by insurance or re-insurance companies of nationally recognized standing having comparable deductibles and providing coverage equal to or greater than the coverage under the cancelled, terminated or lapsed policies for substantially similar premiums are in full force and effect; provided that subject to Section 4.16, the Corporation shall not obtain or re-new any insurance (or re-insurance) policy for a term exceeding 12 months from the date hereof.

4.8   Conduct of Business by the Purchaser

        The Purchaser covenants and agrees with the Partnership, GP and the Corporation that it shall, and shall cause the Purchaser Subsidiaries to, during the period from the date of this Agreement until the earlier of the Effective Time and the time that this Agreement is terminated in accordance with its terms, unless the Partnership Entities and the Corporation shall otherwise agree in writing (such agreement not to be unreasonably withheld or delayed), and except in each case as otherwise permitted or contemplated by this Agreement or the Plan of Arrangement, as contemplated by the Purchaser Disclosure Letter, or as is otherwise required by applicable Law, conduct its business only in, and not take any action except in, the ordinary course of business use all reasonable commercial efforts to maintain and preserve its business organization, assets, employees and advantageous business relationships, and not:

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4.9   Mutual Covenants Regarding the Arrangement

        Until the earlier of the Effective Time and the time that this Agreement is terminated in accordance with its terms, each Party shall perform all obligations required to be performed by such Party under this Agreement, and cooperate with the other Parties in connection therewith and use all commercially reasonable efforts to satisfy (or cause the satisfaction of) the conditions precedent to its obligations hereunder as set forth in Article 5 (to the extent the same is within its control) and to consummate and make effective, as soon as reasonably practicable, the transactions contemplated hereby, including the Arrangement and, without limiting the generality of the foregoing, each Party shall use all commercially reasonable efforts to:

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4.10 Competition Act Approval, Investment Canada Act Approval and HSR Act Approval

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4.11 Purchaser Financing

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4.12 FPA Section 203 Approval

        The Partnership Entities, the Partnership Subsidiaries, the Corporation and the Purchaser shall: (i) as soon as reasonably practicable take all reasonable actions necessary to file or cause to be filed with FERC an application under Section 203 of the FPA and the rules and regulations promulgated thereunder, seeking a FERC order approving the Arrangement ("FPA Section 203 Filing"); and (ii) comply at the earliest practicable date with any request for additional information or documentary material received by the Partnership Entities, the Partnership Subsidiaries, the Corporation or the Purchaser or any of their Subsidiaries from FERC with respect to the FPA Section 203 Filing.

4.13 Covenants of the Partnership Entities Regarding Non-Solicitation

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4.14 Covenants of the Corporation Regarding Non-Solicitation

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4.15 Access to Information; Confidentiality

        From the date hereof until the earlier of the Effective Time and the time this Agreement is terminated in accordance with its terms, subject to compliance with applicable Law and the terms of any existing Contracts and upon reasonable notice, the Partnership Entities shall, and shall cause the Partnership Subsidiaries to, afford to the Purchaser and its officers, employees, advisors, agents and representatives reasonable access, during normal business hours but without any disruption to its normal business operations, to their designated officers, employees, agents, properties, books, records and Contracts in order to permit the Purchaser to be in a position to expeditiously and efficiently integrate the business and operations of the Partnership immediately upon but not prior to the Effective Date. Each of the Parties acknowledges and agrees that information furnished pursuant to this Section 4.15 shall be subject to the terms and conditions of the Confidentiality Agreement.

4.16 Insurance and Indemnification

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4.17 Privacy Issues

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4.18 Title Insurance

        The Partnership shall cooperate with the Purchaser regarding the Purchaser's efforts to obtain an up-to-date title insurance policy for each real property with respect to the Partnership Facilities (in such amounts, on such terms and with such endorsements as determined by the Purchaser). The Purchaser shall be responsible for the costs associated with obtaining such title insurance policies.

4.19 Notice and Cure Provisions

4.20 Pre-Acquisition Reorganization

        Each of the Corporation and the Partnership Entities agree that, upon request by the Purchaser, they shall, and shall (to the extent within its control) cause each Partnership Subsidiary to use all commercially reasonable efforts to (a) effect such reorganizations of the Partnership's or any Partnership Subsidiary's business, operations and assets or such other transaction as the Purchaser may reasonably request (each a "Pre-Acquisition Reorganization"), and (b) co-operate with the Purchaser and its advisors in order to determine the nature of the Pre-Acquisition Reorganizations that might be undertaken and the manner in which they might most effectively be undertaken (including cooperation with the Purchaser to confirm and provide support for all non-capital loss, net capital loss, adjusted cost base and other tax attributes of the Corporation, the Partnership Entities and the Partnership Subsidiaries that may be necessary in connection with any Pre-Closing Reorganization); provided that the Corporation, the Partnership Entities and the Partnership Subsidiaries shall not be required to effect any Pre-Acquisition Reorganization that (i) would be prejudicial in any material respect to any of

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the Partnership Entities, the Corporation, the Partnership Unitholders, the Corporation Shareholders, CPEL, the holders of the Cumulative Redeemable Preferred Shares, Series 1, Cumulative Rate Reset Preferred Shares, Series 2, or Cumulative Floating Rate Preferred Shares, Series 3 of CPEL, the holders of 5.87% Senior Notes due August 15, 2017 and 5.97% Senior Notes due August 15, 2019 issued by CPI Power (US) GP, the holders of 5.9% Senior Notes due July 15, 2014 issued by Curtis Palmer LLC or the holders of the 5.95% medium term notes due June 23, 2036 issued by the Partnership; (ii) would materially delay, impair or impede the completion of the Arrangement; (iii) would unreasonably interfere in the ongoing operations of the Partnership Entities or any of the Partnership Subsidiaries; or (iv) would require the Partnership Entities or any Partnership Subsidiary to contravene any Laws or their respective organization documents.

        The Purchaser shall provide written notice to the Corporation and the Partnership Entities of any proposed Pre-Acquisition Reorganization at least 15 Business Days prior to the anticipated Effective Date. Upon receipt of such notice, the Purchaser, the Corporation and the Partnership Entities shall at the expense of the Purchaser, work co-operatively and use commercially reasonable efforts to prepare prior to the Effective Time all documentation necessary and do all such other acts and things as are necessary to give effect to such Pre-Acquisition Reorganization, and any such Pre-Acquisition Reorganization shall occur as close to the Effective Time as is practical. Notwithstanding the foregoing, the Corporation and the Partnership Entities shall not be required to effect a Pre-Acquisition Reorganization unless they have received an appropriate indemnity indemnifying them for all costs, expenses and losses which they may suffer as a result of such Pre-Acquisition Reorganization, including in connection with the full or partial unwind of any Pre-Acquisition Reorganization, if after participating fully or partially in any Pre-Acquisition Reorganization the Arrangement is not completed other than due to a termination described in Section 6.3(c)(i), (ii) or (iii).

        Without limiting the generality of the foregoing, none of the representations, warranties or covenants of the Partnership Entities or the Corporation shall be deemed to apply to, or deemed breached or violated by or as a result of, any of the transactions requested by the Purchaser pursuant to this Section 4.20.

4.21 Amendment of Constating Documents

        The Parties agree that pursuant to this Agreement and to the Arrangement, the Partnership Agreement and the constating documents of the Corporation, the GP and/or any Partnership Subsidiary shall be amended in a manner satisfactory to the Partnership Entities and the Purchaser, acting reasonably, as may be necessary to facilitate the Arrangement and the satisfaction of covenants made under this Agreement and to ensure that no portion of the Partnership's income for its current fiscal year is allocated to the Purchaser as a result of any distribution made by the Partnership to the Purchaser in accordance with this Agreement or the Plan of Arrangement.

4.22 Additional Covenants

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4.23 Subsidiary Partnership Wind-Up

        The Partnership Entities covenant and agree with the Purchaser that they shall use all commercially reasonable efforts to cause:

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4.24 NC Purchase Agreement

        The Partnership Entities covenant and agree with the Purchaser that they shall use their commercially reasonable efforts to ensure that all closing conditions in their favour under the NC Purchase Agreement are satisfied and satisfy all of the closing conditions to closing in favour of Capital Power Investments LLC under the NC Purchase Agreement (except to the extent waived in writing by Capital Power Investments LLC), prior to the Effective Time and to complete the following transactions prior to the Effective Date:

        The Partnership Entities covenant and agree with the Purchaser that New LLC or New LLC2 shall not undertake any activity except as explicitly provided under this Agreement, the Plan of Arrangement or the Partnership Reorganization Agreements.


ARTICLE 5
CONDITIONS PRECEDENT

5.1   Mutual Conditions Precedent

        The obligations of the Parties to complete the transactions contemplated by this Agreement are subject to the fulfillment, on or before the Effective Time, of each of the following conditions precedent:

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        The foregoing conditions in this Section 5.1 are for the mutual benefit of the Purchaser, the Partnership Entities and the Corporation and may be waived, in whole or in part, jointly by such parties at any time.

5.2   Additional Conditions Precedent to the Obligations of the Partnership Entities

        The obligation of the Partnership Entities to complete the transactions contemplated by this Agreement shall also be subject to the fulfillment of each of the following conditions precedent:

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        The conditions in this Section 5.2 are for the exclusive benefit of the Partnership Entities and may be asserted by the Partnership Entities regardless of the circumstances or may be waived by the Partnership Entities in their sole discretion, in whole or in part, at any time and from time to time without prejudice to any other rights which the Partnership Entities may have.

5.3   Additional Conditions Precedent to the Obligation of the Corporation

        The obligation of the Corporation to complete the transactions contemplated by this Agreement shall also be subject to the fulfillment of each of the following conditions precedent:

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        The conditions in this Section 5.3 are for the exclusive benefit of the Corporation and may be asserted by the Corporation regardless of the circumstances or may be waived by the Corporation in its sole discretion, in whole or in part, at any time and from time to time without prejudice to any other rights which the Corporation may have.

5.4   Additional Conditions Precedent to the Obligations of the Purchaser

        The obligation of the Purchaser to complete the transactions contemplated by this Agreement shall also be subject to the fulfillment of each of the following conditions precedent:

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        The conditions in this Section 5.4 are for the exclusive benefit of the Purchaser and may be asserted by the Purchaser regardless of the circumstances or may be waived by the Purchaser in its sole discretion, in whole or in any part, at any time and from time to time without prejudice to any other rights which the Purchaser may have.

5.5   Satisfaction of Conditions

        The conditions precedent set out in Sections 5.1, 5.2, 5.3 and 5.4 shall be conclusively deemed to have been satisfied, waived or released when, with the agreement of the Partnership Entities, the Corporation and the Purchaser, Articles of Arrangement are filed under the CBCA in respect of the Arrangement.


ARTICLE 6
AMENDMENT AND TERMINATION

6.1   Amendment

        This Agreement and the Plan of Arrangement may, at any time and from time to time before or after the holding of the Partnership Meeting but not later than the Effective Date, be amended by written agreement of the Parties, without further notice to or authorization on the part of the Partnership Unitholders or the Corporation Shareholders (subject to the Interim Order, the Final Order and applicable Laws), and any such amendment may, without limitation:

        provided that no such amendment may (i) reduce or materially adversely affect the consideration to be received by the Partnership Unitholders without approval by the Partnership Unitholders given in the same manner as required for the approval of the Arrangement or as may be ordered by the Court, or (ii) reduce or materially adversely affect the consideration to be received by (or otherwise be reasonably be expected to be adverse to the economic interests of) any Corporation Shareholder without approval by such Corporation Shareholder given in the same manner as required for the approval of the Arrangement or as may be ordered by the Court.

6.2   Term

        This Agreement shall be effective from the date hereof until the earlier of the Effective Time and the time this Agreement is terminated in accordance with its terms.

6.3   Termination

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6.4   Purchaser Termination Fee

        Notwithstanding any other provision of this Agreement relating to the payment of fees or expenses, including the payment of brokerage fees, the Partnership shall pay, or cause to be paid, to the Purchaser within the time specified by wire transfer of immediately available funds an amount equal to $35 million (the "Purchaser Termination Fee") if:

6.5   Partnership Termination Fee

        Notwithstanding any other provision of this Agreement relating to the payment of fees or expenses, including the payment of brokerage fees, the Purchaser shall pay, or cause to be paid, to the Partnership by wire transfer of immediately available funds an amount equal to $35 million (the "Partnership Termination Fee") if:

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6.6   Expense Reimbursement

6.7   Liquidated Damages, Injunctive Relief and No Liability of Others

        The Parties acknowledge and agree that the payment of the Purchaser Termination Fee or the Partnership Termination Fee set out in Sections 6.4 and 6.5 respectively, is the payment of liquidated damages that are a genuine pre-estimate of the damages the Parties will suffer or incur, as applicable, as a result of the event giving rise to such payment and the resultant termination of this Agreement and is not a penalty. Each of Parties irrevocably waives any rights they may have to raise as a defense that any such liquidated damages are excessive or punitive. For greater certainty, the Parties agree that the right to receive payment of the amount pursuant to Section 6.4, 6.5 or 6.6 in the manner provided therein is the sole remedy of the recipient as a result of the event giving rise to such payment and the resultant termination of this Agreement and the recipient shall have no further claim or remedy against the other Parties. Except as specifically provided herein, there shall be no liability of any shareholder, Unitholder or Agent of the Purchaser, the Partnership Entities or the Corporation, or of any of their Subsidiaries or Affiliates in connection with any liability or other obligation of the Purchaser, the Partnership Entities or the Corporation, or of any of their Subsidiaries or Affiliates, whether hereunder or otherwise in connection with the transactions contemplated hereby.


ARTICLE 7
GENERAL PROVISIONS

7.1   Notices

        All notices and other communications given or made pursuant hereto shall be in writing and shall be deemed to have been duly given or made as of the date delivered or sent if delivered personally or sent by facsimile or e-mail transmission, or as of the following Business Day if sent by prepaid overnight courier, to the Parties at the following addresses (or at such other addresses as shall be specified by any Party by notice to the other given in accordance with these provisions):


(a)

 

if to the Partnership:
5th Floor, TD Tower
10088—102 Avenue
Edmonton, AB T5J 2Z1

 

 

Attention:

 

Senior Vice President, General Counsel & Corporate Secretary
    Facsimile No.:   (780) 392-5200
    Email:   kchisholm@capitalpower.com

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with a copy (which shall not constitute notice) to:
Fraser Milner Casgrain LLP
15th Floor, Bankers Court
850—2nd Street S.W.
Calgary, AB T2P 0R8

 

 

Attention:

 

Bill Gilliland
    Facsimile No.:   (403) 268-3100
    Email:   bill.gilliland@fmc-law.com

 

 

—and—
Norton Rose OR LLP
Suite 1000, 110—9th Avenue S.W.
Calgary, Alberta T2P 0T1

 

 

Attention:

 

Crispin Arthur
    Facsimile No.:   (403) 355-3551
    Email:   crispin.arthur@nortonrose.com

(b)

 

if to GP:
5th Floor, TD Tower
10088—102 Avenue
Edmonton, AB T5J 2Z1

 

 

Attention:

 

Senior Vice President, General Counsel & Corporate Secretary
    Facsimile No.:   (780) 392-5200
    Email:   kchisholm@capitalpower.com

 

 

with a copy (which shall not constitute notice) to:
Fraser Milner Casgrain LLP
15th Floor, Bankers Court
850—2nd Street S.W.
Calgary, AB T2P 0R8

 

 

Attention:

 

Bill Gilliland
    Facsimile No.:   (403) 268-3100
    Email:   bill.gilliland@fmc-law.com

 

 

—and—
Norton Rose OR LLP
Suite 1000, 110—9th Avenue S.W.
Calgary, Alberta T2P 0T1

 

 

Attention:

 

Crispin Arthur
    Facsimile No.:   (403) 355-3551
    Email:   crispin.arthur@nortonrose.com

(c)

 

if to the Corporation:
5th Floor, TD Tower
10088—102 Avenue
Edmonton, AB T5J 2Z1

 

 

Attention:

 

Senior Vice President, General Counsel & Corporate Secretary

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    Facsimile No.:   (780) 392-5200
    Email:   kchisholm@capitalpower.com

 

 

with a copy (which shall not constitute notice) to:
Fraser Milner Casgrain LLP
15th Floor, Bankers Court
850—2nd Street S.W.
Calgary, AB T2P 0R8

 

 

Attention:

 

Bill Gilliland
    Facsimile No.:   (403) 268-3100
    Email:   bill.gilliland@fmc-law.com

 

 

—and—
Norton Rose OR LLP
Suite 1000, 110—9th Avenue S.W.
Calgary, Alberta T2P 0T1

 

 

Attention:

 

Crispin Arthur
    Facsimile No.:   (403) 355-3551
    Email:   crispin.arthur@nortonrose.com

(d)

 

if to the Purchaser:
Atlantic Power Corporation
200 Clarendon Street, 25th Floor
Boston, MA 02116
USA

 

 

Attention:

 

Barry Welch
    Facsimile No.:   (617) 977-2410
    E-mail:   bwelch@atlanticpower.com

 

 

with a copy (which shall not constitute notice) to:
Goodmans LLP
Bay Adelaide Centre
333 Bay Street, Suite 3400
Toronto, ON M5H 2S7

 

 

Attention:

 

Bill Gorman
    Facsimile No.:   (416) 979-1234
    E-mail:   bgorman@goodmans.ca

 

 

—and—
Leonard, Street and Deinard
150 South Fifth Street
Suite 2300
Minneapolis, MN 55402
USA

 

 

Attention:

 

Tammie Ptacek
    Facsimile No.:   (612) 335-1657
    E-mail:   tammie.ptacek@leonard.com

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7.2   Entire Agreement, Binding Effect and Assignment

        This Agreement shall be binding on and shall enure to the benefit of the Parties and their respective successors and permitted assigns. This Agreement (including the schedules hereto), the Partnership Entity Disclosure Letter, the Corporation Disclosure Letter, the Purchaser Disclosure Letter and the Confidentiality Agreement constitute the entire agreement, and supersede all other prior agreements and understandings, both written and oral, between the Parties with respect to the subject matter hereof and thereof. Neither this Agreement nor any of the rights, interests or obligations hereunder may be assigned by any of the Parties without the prior written consent of the other Parties. The Parties hereby confirm that they remain bound by the terms of the Confidentiality Agreement in accordance with the terms thereof, notwithstanding that this Agreement may be terminated for any reason whatsoever.

7.3   Severability

        If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule or Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any Party.

        Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the fullest extent possible.

7.4   No Third Party Beneficiaries

        Except as provided in Sections 4.16 and 7.10 and except for the rights of the Partnership Unitholders and the Corporation Shareholders to receive the consideration for their Partnership Units and the Corporation Shares, respectively, following the Effective Time, and other rights and benefits, pursuant to the Arrangement, which rights are hereby acknowledged and agreed by the Purchaser, this Agreement is not intended to confer any rights or remedies upon any person other than the Parties to this Agreement. This Section 7.4 shall survive the Effective Time and any termination of this Agreement.

7.5   Time of Essence

        Time shall be of the essence in this Agreement.

7.6   Further Assurances

        Each Party hereto shall, from time to time and at all times hereafter, at the request of the other Party hereto, but without further consideration, do all such further acts, and execute and deliver all such further documents and instruments and provide all such further assurances as may be reasonable required in order to fully perform and carry out the terms and intent hereof.

7.7   Remedies

        Except as provided in Section 6.7, the Parties agree that irreparable harm would occur for which money damages would not be an adequate remedy at law in the event that any of the provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached. It is accordingly agreed that the Parties shall be entitled to equitable remedies, including specific performance, a restraining order and interlocutory, preliminary and permanent injunctive relief and other equitable relief to prevent breaches of this Agreement, any requirement for the securing or

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posting of any bond in connection with the obtaining of any such injunctive or other equitable relief hereby being waived. Except as provided in Section 6.7, such remedies will not be the exclusive remedies for any breach of this Agreement but will be in additions to all other remedies available at law or equity to each of the Parties.

7.8   Costs and Expenses

        Except as provided in Sections 4.10 and 6.6 and as otherwise agreed to in writing between the Parties, the Parties agree that all costs and expenses of the Parties relating to the Arrangement and the transactions contemplated hereby, including legal fees, accounting fees, financial advisory fees, regulatory filing fees, stock exchange fees, all disbursements of advisors and printing and mailing costs, shall be paid by the Party incurring such expenses.

7.9   Governing Law

        This Agreement shall be governed, including as to validity, interpretation and effect, by the laws of the Province of Alberta and the federal laws of Canada applicable therein, and shall be construed and treated in all respects as an Alberta contract. Each of the Parties hereby irrevocably attorns to the exclusive jurisdiction of the Courts in the Province of Alberta in respect of all matters arising under and in relation to this Agreement and the Arrangement.

7.10 Notice of Limitation

        The Purchaser covenants and agrees that no Partnership Unitholder shall have any liability for or obligation in respect of, the covenants and obligations of the Partnership hereunder. This Section 7.10 shall survive the Effective Time and any termination of this Agreement.

7.11 Filing of Agreement

        The Parties acknowledge and agree that this Agreement and all other documents required under applicable Securities Laws will be filed on the SEDAR and/or EDGAR website, together with other documents required by Securities Law.

7.12 Waiver

        Any Party may, on its own behalf only, (i) extend the time for the performance of any of the obligations or acts of another Party, (ii) waive compliance with another Party's agreements or the fulfillment of any conditions to its own obligations contained herein, or (iii) waive inaccuracies in another Party's representations or warranties contained herein or in any document delivered by another Party; provided, however, that any such extension or waiver shall be valid only if set forth in an instrument in writing signed on behalf of such Party and, unless otherwise provided in the written waiver, will be limited to the specific breach or condition waived.

7.13 Counterparts, Execution

        This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument. The Parties shall be entitled to rely upon delivery of an executed facsimile or similar executed electronic copy of this Agreement, and such facsimile or similar executed electronic copy shall be legally effective to create a valid and binding agreement among the Parties.

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        IN WITNESS WHEREOF the Parties have caused this Agreement to be executed as of the date first written above by their respective officers thereunto duly authorized.

    CAPITAL POWER INCOME L.P., by its general partner, CPI INCOME SERVICES LTD.

 

 

Per:

 

/s/ FRANCOIS POIRIER

        Name:   Francois Poirier
        Title:   Independent Director

 

 

Per:

 

/s/ ALLEN HAGERMAN

        Name:   Allen Hagerman
        Title:   Director

 

 

CPI INCOME SERVICES LTD.

 

 

Per:

 

/s/ STUART LEE

        Name:   Stuart Lee
        Title:   President

 

 

Per:

 

/s/ K. CHISHOLM

        Name:   B. Kathryn Chisholm
        Title:   Senior Vice-President, General Counsel and Corporate Secretary

 

 

CPI INVESTMENTS INC.

 

 

Per:

 

/s/ BRIAN VAASJO

        Name:   Brian Vaasjo
        Title:   President and Chief Executive Officer

 

 

Per:

 

/s/ STUART LEE

        Name:   Stuart Lee
        Title:   Senior Vice President and Chief Financial Officer

 

 

ATLANTIC POWER CORPORATION

 

 

Per:

 

/s/ BARRY WELCH

        Name:   Barry Welch
        Title:   President and Chief Executive Officer

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SCHEDULE A

PLAN OF ARRANGEMENT
UNDER SECTION 192
OF THE CANADA BUSINESS CORPORATIONS ACT

ARTICLE 1
INTERPRETATION

1.1   Definitions.

        In this Plan of Arrangement the following terms shall have the respective meanings set out below and grammatical variations of such terms shall have corresponding meanings:

        "Aggregate Cash Elected" means the aggregate amount of cash that would be payable to Partnership Unitholders and CPLP based upon the elections to receive the Cash Consideration made pursuant to Sections 2.5 and 2.6 and before giving effect to the pro-ration provisions of Section 2.4;

        "Aggregate Cash Maximum" has the meaning ascribed to it in Section 2.4(a);

        "Aggregate Share Maximum" has the meaning ascribed to it in Section 2.4(b);

        "Aggregate Shares Elected" means the aggregate number of Purchaser Shares that would be payable to Partnership Unitholders and CPLP based upon the elections to receive the Share Consideration made or deemed to be made pursuant to Sections 2.5 and 2.6 and before giving effect to the pro-ration provisions of Section 2.4;

        "Arrangement" means an arrangement under section 192 of the CBCA on the terms and subject to the conditions set out in the Arrangement Agreement and herein as supplemented, modified or amended in accordance with the terms hereof or the Arrangement Agreement or at the direction of the Court in the Final Order;

        "Arrangement Agreement" means the arrangement agreement dated June 20, 2011 among the Partnership, GP, the Corporation and the Purchaser, as the same may be amended, supplemented or otherwise modified from time to time in accordance with the terms thereof;

        "Arrangement Resolution" means the extraordinary resolution of the Partnership Unitholders in respect of the Arrangement to be considered by the Partnership Unitholders at the Partnership Meeting, substantially in the form and content of Schedule D to the Arrangement Agreement;

        "Articles of Arrangement" means the articles of arrangement in respect of the Arrangement, required by the CBCA to be sent to the Director after the Final Order is made, which shall be in a form and content satisfactory to the Partnership, GP, the Corporation and the Purchaser, each acting reasonably;

        "Benefit Plans" means any pension or retirement income, benefit, supplemental benefit, stock option, restricted stock, stock appreciation right, restricted stock unit, phantom stock or other equity-based compensation plan, deferred compensation, severance, health, welfare, medical, dental, disability plans or any other employee compensation or benefit plans, policies, programs or other arrangements and all related agreements and policies with third parties such as trustees or insurance companies, which are maintained by a Party or any of its Subsidiaries with respect to any of their current or former employees, directors, officers or other individuals providing services to such Party or any of its Subsidiaries including, without limitation, "plans" as defined in section 3(3) of the U.S. Employee Retirement Income Security Act of 1974, as amended;

        "Bridge Loans" has the meaning ascribed to it in the Arrangement Agreement;

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        "Business Day" means any day other than a Saturday, Sunday or a statutory or civic holiday in the Province of Alberta or Ontario or the State of Massachusetts or New York;

        "Cash Consideration" means, for each Partnership Unit held, $19.40 in cash, or, in respect of CPLP, that amount of cash as determined pursuant to Section 2.6(b);

        "Cash Reduction" has the meaning ascribed to it in Section 2.4(a);

        "CBCA" means the Canada Business Corporations Act, R.S.C. 1985, c.C-44, as amended, and the regulations made thereunder;

        "Certificate of Arrangement" means the certificate to be issued by the Director pursuant to subsection 192(7) of the CBCA giving effect to the Arrangement;

        "Class A Corporation Shares" means the Class A Shares in the capital of the Corporation;

        "Class B Corporation Shares" means the Class B Shares in the capital of the Corporation;

        "Corporation" means CPI Investments Inc., a corporation incorporated under the CBCA;

        "Corporation Letter of Transmittal and Election Form" means the letter of transmittal and election form to be sent by the Corporation to CPLP and EPCOR in connection with the Arrangement;

        "Corporation Shareholders" means holders of Corporation Shares, being EPCOR and CPLP;

        'Corporation Shares" means, collectively, the Class A Corporation Shares and the Class B Corporation Shares;

        "Court" means the Court of Queen's Bench of Alberta;

        "CPLP" means Capital Power L.P., a limited partnership established under the laws of the Province of Ontario;

        "Depositary" means Computershare Investor Services Inc.;

        "Distribution Agreement" means the distribution agreement to be entered into at the Effective Time among CPI Power Holdings Inc., New LLC, CPI Preferred Equity Ltd., the Partnership and the Purchaser in the form set forth in Schedule F to the Arrangement Agreement;

        "Director" means the Director or a Deputy Director appointed pursuant to section 260 of the CBCA;

        "Effective Date" means the date shown on the Certificate of Arrangement, which date shall be determined in accordance with Section 2.6 of the Arrangement Agreement;

        "Effective Time" means 12:01 a.m. (Edmonton time) on the Effective Date, or such other time as agreed to in writing by the Partnership and the Purchaser;

        "Election Deadline" means 5:00 p.m. (Edmonton time) at the place of deposit indicated in the Letter of Transmittal and Election Form or the Corporation Letter of Transmittal and Election Form, as the case may be, on the date which is three Business Days prior to the date of the Partnership Meeting;

        "Eligible Holder" means CPLP and any Partnership Unitholder, other than a Person that is exempt from tax under Part I of the Tax Act, and includes a partnership that is a Partnership Unitholder if one or more of its partners would, if directly a Partnership Unitholder, otherwise be an Eligible Holder;

        "EPCOR" means EPCOR Utilities Inc., a corporation incorporated under the Business Corporations Act (Alberta);

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        "Exchange Ratio" means 1.3;

        "Final Corporation Dividend" has the meaning ascribed to it in Section 2.3(d);

        "Final GP Dividend" has the meaning ascribed to it in Section 2.3(c);

        "Final Order" means the final order of the Court approving the Arrangement to be applied for by the Partnership, GP and the Corporation following the Partnership Meeting and to be granted pursuant to subsection 192(4) of the CBCA in respect of the Partnership, GP and the Corporation, as such order may be affirmed, amended or modified by the Court (with the consent of each of the Partnership, GP, the Corporation and the Purchaser, each acting reasonably) at any time prior to the Effective Date or, if appealed, then, unless such appeal is withdrawn or denied, as affirmed or as amended (provided that such amendment is acceptable to each of the Partnership, GP, the Corporation and the Purchaser, each acting reasonably) on appeal;

        "Final Partnership Distribution" has the meaning ascribed to it in Section 2.3(b);

        "Governmental Entity" means any applicable (i) multinational, federal, provincial, state, regional, municipal, local or other government, governmental or public department, ministry, central bank, court, tribunal, arbitral body, commission, commissioner, board, bureau or agency, domestic or foreign, (ii) stock exchange, including each of the Toronto Stock Exchange and the New York Stock Exchange; (iii) subdivision, agent or authority of any of the foregoing or (iv) quasi-governmental or private body, including any tribunal, commission, regulatory agency or self-regulatory organization, exercising any regulatory, expropriation or taxing authority under or for the account of any of the foregoing;

        "GP" means CPI Income Services Ltd., the general partner of the Partnership, and a corporation incorporated under the CBCA;

        "Holder Notes" has the meaning ascribed to it in Section 4.1(e);

        "Interim Order" means the interim order of the Court concerning the Arrangement under subsection 192(4) of the CBCA in respect of the Partnership, GP and the Corporation, containing declarations and directions with respect to the Arrangement and the holding of the Partnership Meeting, as such order may be affirmed, amended or modified by any court of competent jurisdiction with the consent of the Partnership, GP, the Corporation and the Purchaser, each acting reasonably;

        "Law"or"Laws" means all laws, statutes, codes, ordinances, decrees, rules, regulations, bylaws, statutory rules, judicial or arbitral or administrative or ministerial or departmental or regulatory judgments, orders, decisions, rulings, injunctions, determinations, awards or other requirements, and terms and conditions of any permit, grant of approval, permission, authority or licence of any Governmental Entity, statutory body or self-regulatory authority (including the Toronto Stock Exchange and the New York Stock Exchange), and the term "applicable" with respect to such Laws and in the context that refers to one or more Persons, means that such Laws apply to such Person or Persons and/or its Subsidiaries or its or their business, undertaking, property, Benefit Plans or securities and emanate from a Governmental Entity having jurisdiction over the Person or Persons and/or its Subsidiaries or its or their business, undertaking or securities;

        "Letter of Transmittal and Election Form" means, where the context requires, the letter of transmittal and election form to be sent by the Partnership to the Partnership Unitholders in connection with the Arrangement;

        "Lien" means any hypothec, mortgage, pledge, assignment, lien, charge, security interest, encumbrance or adverse right or claim, other third Person interest or encumbrance of any kind, whether contingent or absolute, and any agreement, option, right or privilege (whether by law, contract or otherwise) capable of becoming any of the foregoing;

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        "NC Purchase Agreement" means the membership interest purchase agreement dated June 20, 2011 between CPI USA Holdings LLC, CPI Power Holdings Inc. and Capital Power Investments LLC in the form set forth in Schedule G to the Arrangement Agreement;

        "New LLC" means the limited liability company to be established pursuant to the laws of the State of Delaware prior to the Effective Date and wholly-owned by CPI Power Holdings, Inc.;

        "New LLC2" means the limited liability company to be established pursuant to the laws of the State of Delaware prior to the Effective Date and wholly-owned by New LLC;

        "Partnership" means Capital Power Income L.P., a partnership existing under the laws of the Province of Ontario;

        "Partnership Agreement" means the amended and restated limited partnership agreement of the Partnership made effective as of November 4, 2009;

        "Partnership Meeting" means the special meeting of Partnership Unitholders, including any adjournment or postponement thereof, to be held to consider the Arrangement Resolution;

        "Partnership Subsidiaries" means all Subsidiaries of the Partnership, and which, for purposes of this Plan of Arrangement, shall not include CPI USA North Carolina LLC, New LLC, New LLC2, PERH or any Subsidiary of PERH;

        "Partnership Unitholders" means holders of Partnership Units;

        "Partnership Units" means the limited partnership units of the Partnership;

        "PERH" means Primary Energy Recycling Holdings LLC;

        "Person" includes an individual, limited or general partnership, limited liability company, limited liability partnership, trust, joint venture, association, body corporate, unincorporated organization, trustee, executor, administrator, legal representative, government (including any Governmental Entity) or any other entity, whether or not having legal status;

        "Purchaser" means Atlantic Power Corporation, a corporation continued under the laws of the Province of British Columbia;

        "Purchaser Note" means the non-interest bearing promissory note to be issued by the Purchaser in favour of CPLP in the principal amount of $121,405,211 as part of this Plan of Arrangement;

        "Purchaser Shares" means the common shares in the capital of the Purchaser;

        "Share Consideration" means, for each Partnership Unit held, the number of Purchaser Shares equal to the Exchange Ratio or, in respect of CPLP, that number of Purchaser Shares as determined pursuant to Section 2.6(c).

        "Share Reduction" has the meaning ascribed to it in Section 2.4(b);

        "Section 85 Election" has the meaning ascribed to it in Section 5.1;

        "Subsidiary" has the meaning ascribed to it in National Instrument 45-106—Prospectus and Registration Exemptions;

        "Tax" or "Taxes" means all federal, state, provincial, territorial, county, municipal, local or foreign taxes, duties, imposts, levies, assessments, tariffs and other charges imposed, assessed or collected by a Governmental Entity including (i) any gross income, net income, gross receipts, business, royalty, capital, capital gains, goods and services, value added, severance, stamp, franchise, occupation, premium, capital stock, sales and use, real property, land transfer, personal property, ad valorem, transfer, licence, profits, windfall profits, environmental, payroll, employment, employer health, pension plan, anti-dumping, countervail, excise, severance, stamp, occupation, or premium tax, (ii) all

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withholdings for taxes on amounts paid to or by the relevant person, (iii) all employment insurance premiums, Canada, and any other pension plan contributions or premiums and worker's compensation premiums and contributions, (iv) any fine, penalty, interest or addition to tax, (v) any tax imposed, assessed, or collected or payable pursuant to any tax-sharing agreement or any other contract relating to the sharing or payment of any such tax, levy, assessment, tariff, duty, deficiency, or fee, and (vi) any liability for any of the foregoing as a transferee, successor, guarantor, or by contract or by operation of Law;

        "Tax Act" means the Income Tax Act (Canada) and the regulations made thereunder, as amended; and

        "Tax Returns" means all reports, forms, elections, designations, schedules, statements, estimates, declarations of estimated Tax, information statements and returns required to be filed, or in fact filed, with a Governmental Entity with respect to Taxes.

1.2   Interpretation Not Affected by Headings, etc.

        The division of this Plan of Arrangement into Articles, Sections and other portions and the insertion of headings are for reference purposes only and shall not affect the interpretation of this Plan of Arrangement. Unless otherwise indicated, any reference in this Plan of Arrangement to "Article" or "Section" followed by a number refers to the specified Article or Section of this Plan of Arrangement. The terms "this Plan of Arrangement", "hereof', "herein", "hereunder" and similar expressions refer to this Plan of Arrangement, and any amendments, variations or supplements hereto made in accordance Article 4 hereof or made at the direction of the Court in the Final Order and do not refer to any particular Article, Section or other portion of this Plan of Arrangement.

1.3   Rules of Construction.

        In this Plan of Arrangement, unless the context otherwise requires, (a) words importing the singular number include the plural and vice versa, (b) words importing any gender include all genders, and (c) "include", "includes" and "including" shall be deemed to be followed by the words "without limitation".

1.4   Time.

        Time shall be of the essence in every matter or action contemplated hereunder.

1.5   Currency.

        All references in this Plan of Arrangement to sums of money and payments to be made hereunder are expressed in lawful money of Canada.

1.6   Statutes.

        Any reference to a statute includes all rules and regulations made pursuant to such statute and, unless otherwise specified, the provisions of any statute or regulation or rule which amends, supplements or supersedes any such statute, regulation or rule.

1.7   Business Days.

        Whenever any action to be taken or payment or delivery to be made pursuant to this Plan of Arrangement would otherwise be required to be made on a day that is not a Business Day, such action shall be taken or such payment shall be made on the first Business Day following such day.

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ARTICLE 2
ARRANGEMENT

2.1   Arrangement Agreement.

        This Plan of Arrangement is made pursuant to, is subject to the provisions of and forms part of the Arrangement Agreement, and constitutes an arrangement as referred to in section 192 of the CBCA.

2.2   Binding Effect.

        This Plan of Arrangement will without any further authorization, act or formality of the Court become effective on, and be binding on and after, the Effective Time on the Partnership, the Partnership Unitholders, GP, the Corporation, the Corporation Shareholders and the Purchaser.

2.3   Arrangement.

        Commencing at the Effective Time, the following events set out in this Section 2.3 shall occur and shall be deemed to occur consecutively in the order set out in this Section 2.3, each occurring five minutes following the completion of the previous event (unless otherwise specified), without any further authorization, act or formality:

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2.4   Maximum Cash Amount and Maximum Share Amount.

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2.5   Partnership Unitholder Election.

        Subject to Section 2.4 hereof, with respect to the election required to be made by a Partnership Unitholder pursuant to Section 2.3(g):

2.6   CPLP Election.

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2.7   Adjustments to Share Consideration.

        Other than Partnership Units, if any, issued by the Partnership in the month of June 2011 pursuant to and in accordance with the terms of the Partnership's distribution reinvestment plan effective October 13, 2009, the Share Consideration shall be adjusted to reflect fully the effect of any stock split, reverse split, stock dividend (including any dividend or distribution of securities convertible into Purchaser Shares, Partnership Units or Corporation Shares, other than stock dividends paid in lieu of ordinary course dividends), consolidation, reorganization, recapitalization or other like change with respect to Purchaser Shares, Partnership Units or Corporation Shares occurring after the date of the Arrangement Agreement and prior to the Effective Time.

ARTICLE 3
CERTIFICATES AND DELIVERY

3.1   Exchange of Corporation Shares

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3.2   Exchange of Partnership Units and Final Partnership Distribution.

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3.3   Fractional Purchaser Shares.

        In no event shall any holder of Partnership Units or Corporation Shares be entitled to receive a fractional Purchaser Share in consideration therefore. Where the aggregate number of Purchaser Shares to be issued to a holder of Partnership Units or to CPLP as consideration under this Arrangement would result in a fraction of a Purchaser Share being issuable, the number of Purchaser Shares to be received by such holder or CPLP shall be rounded down to the nearest whole number of Purchaser Shares and neither CPLP nor any Partnership Unitholder will be entitled to any compensation in respect of such fractional Purchaser Share.

3.4   Fractional Cash.

        Any cash payable to a Partnership Unitholder or a Corporation Shareholder pursuant to the Arrangement shall be rounded down to the nearest whole cent.

3.5   Dividends and Distributions with Respect to Unsurrendered Certificates.

        No dividend or other distribution declared or made after the Effective Time with respect to the Purchaser Shares with a record date after the Effective Time shall be delivered to the holder of any unsurrendered certificate that, immediately prior to the Effective Time, represented outstanding Partnership Units or Corporation Shares unless and until the holder of such certificate shall have surrendered such certificate in accordance with Section 3.2(c) or Section 3.1(c), as the case may be, or complied with Section 3.2(f) or Section 3.1(f), as the case may be. Subject to applicable Law and Section 3.2 or Section 3.1 hereof, as the case may be, at the time of such surrender or compliance, there shall, in addition to the delivery of certificates representing Purchaser Shares to which such Partnership Unitholder or Corporation Shareholder, as the case may be, is thereby entitled, be delivered to such holder, without interest, the amount of the dividend or other distribution with a record date after the Effective Time theretofore paid with respect to such Purchaser Shares.

3.6   Withholding Rights.

        A holder of Partnership Units or Corporation Shares shall be liable for, and the Purchaser and the Depositary shall be entitled to deduct and withhold from any amount paid to such holder, such amounts as each of the Purchaser or the Depositary is required or permitted to deduct and withhold under the Tax Act, the United States Internal Revenue Code of 1986, as amended, or any provision of applicable federal, provincial, state, local or foreign Tax Law with respect to any consideration otherwise payable hereunder to such holder, and the Purchaser and the Depositary shall be entitled to recover from such holder any portion of such amounts that is required to be withheld thereunder and is not otherwise deducted or withheld. To the extent that amounts are so withheld, such withheld amounts shall be treated for all purposes hereof as having been paid to the holder of the Corporation Shares or Partnership Units, as the case may be, in respect of which such deduction and withholding was made, provided that such withheld amounts are actually remitted by the Purchaser or the Depositary to the appropriate taxing authority in the name of the relevant holder of Corporation Shares or the Partnership Units. To the extent that the amount so required or entitled to be deducted

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or withheld from any payment to such a holder exceeds the cash portion of the consideration otherwise payable to the holder, the Purchaser and the Depositary are hereby authorized to sell or otherwise dispose of such portion of the Purchaser Shares otherwise deliverable to such holder as is necessary to provide sufficient funds to the Purchaser or the Depositary, as the case may be, to enable it to comply with such deduction or withholding requirement or entitlement and the Purchaser or the Depositary shall notify the holder thereof and remit to such holder any unapplied balance of the net proceeds of such sale.

ARTICLE 4
AMENDMENTS

4.1   Amendments to Plan of Arrangement.

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ARTICLE 5
OTHER TAX MATTERS

5.1   Tax Election.

        An Eligible Holder whose Partnership Units or Corporation Shares are exchanged for consideration that includes Purchaser Shares and who deposits, or causes its agent or other representative to deposit, prior to the Election Deadline with the Depositary, a duly completed Letter of Transmittal and Election Form or Corporation Letter of Transmittal and Election Form, as the case may be, indicating such holder's intention to file a Section 85 Election shall be entitled to make an income tax election, pursuant to section 85 of the Tax Act (and any analogous provision of provincial income tax law) (a "Section 85 Election") with respect to the exchange by completing and forwarding two signed copies of the prescribed form of election to an appointed representative, as directed by the Purchaser, on or before 90 days after the Effective Date, duly completed with the details of the number of Partnership Units transferred and the applicable agreed amounts for the purposes of such joint elections. The Purchaser shall, within 60 days after receiving the completed joint election forms from an Eligible Holder, and subject to such joint election forms being correct and complete and in compliance with requirements imposed under the Tax Act (or applicable provincial income tax law), sign and return such forms to the Eligible Holder for filing with the Canada Revenue Agency (or the applicable provincial tax authority). Neither the Purchaser, the Partnership, GP nor any successor corporation shall be responsible for the proper completion of any election form nor, except for the obligation to sign and return duly completed election forms which are received within 90 days of the Effective Date, for any Taxes, interest or penalties resulting from the failure of a holder of Partnership Units to properly complete or file such election forms in the form and manner and within the time prescribed by the Tax Act (or any applicable provincial legislation). In its sole discretion, the Purchaser or any successor corporation may choose to sign and return an election form received by it more than 90 days following the Effective Date or from an Eligible Holder who did not deposit, or cause its agent or other representative to deposit, prior to the Election Deadline with the Depositary, a duly completed Letter of Transmittal and Election Form or Corporation Letter of Transmittal and Election Form, as the case may be, indicating such holder's intention to file a Section 85 Election, but will have no obligation to do so.

5.2   Tax Returns and Tax Elections.

        Except as otherwise required by any applicable Law, the Partnership, the Purchaser and GP shall not and shall not allow the Partnership or any Partnership Subsidiary to amend, refile or otherwise modify or grant an extension or waiver with respect to any Tax Return for the Partnership or the Partnership Subsidiaries for any taxation year, or part of a taxation year, ending on or before the Effective Date if such amendment, refiling, modification or extension would cause any current or past

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member of the Partnership to be subject to any additional liability for Taxes payable nor shall the Purchaser request an audit or assessment of any such Tax Return or extend the period during which a current or past member of the Partnership would be liable for additional Taxes payable without the approval of the Court.

ARTICLE 6
FURTHER ASSURANCES

6.1   Further Assurances.

        Notwithstanding that the transactions and events set out herein shall occur and be deemed to occur in the order set out in this Plan of Arrangement without any further act or formality, each of the parties to the Arrangement Agreement shall make, do and execute, or cause to be made, done and executed, all such further acts, deeds, agreements, transfers, assurances, instruments or documents as may reasonably be required by any of them in order further to document or evidence any of the transactions or events set out herein.

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SCHEDULE C

PARTNERSHIP SUPPORT AGREEMENTS

LOGO

SUPPORT AGREEMENT

June 20, 2011

TO:
CAPITAL POWER L.P. and CAPITAL POWER CORPORATION

Dear Sir/Madam:

Re:
Proposed Acquisition by Atlantic Power Corporation (the "Purchaser") of Capital Power Income L.P. (the "Partnership") and CPI Investments Inc. (the "Corporation")

        Reference is made to the Arrangement Agreement dated as of the date hereof (the "Arrangement Agreement") among the Purchaser, the Partnership, CPI Income Services Ltd., and the Corporation regarding the proposed acquisition of the Partnership and the Corporation by the Purchaser pursuant to a plan of arrangement under the Canada Business Corporations Act on the terms and conditions set out in the Arrangement Agreement (the "Proposed Transaction"). The entering into of the Arrangement Agreement by the Purchaser is subject to, among other things, the execution and delivery of this Support Agreement and the approval of the Arrangement by the Corporation Shareholders.

        All capitalized terms and phrases used in this Support Agreement but not defined herein shall have the respective meanings given to them in the Arrangement Agreement.

        The purpose of this Support Agreement is to confirm the commitment of the undersigned securityholder of the Corporation (the "Securityholder") to vote or cause to be voted at any meeting of holders of the Corporation Shares, including any adjournment or postponement thereof, or in any other circumstances (including by way of written resolution) upon which a vote, consent or other approval with respect to the special resolution and/or any other resolution to approve the Arrangement and any ancillary matters required to give legal effect to the foregoing is sought (the "Corporation Transaction Approvals"), all Corporation Shares owned (beneficially or otherwise) by the Securityholder, directly or indirectly, or over which the Securityholder exercises control or direction (collectively, the "Subject Securities"), in favour of the Arrangement and to otherwise support the Proposed Transaction on the terms and conditions of this Support Agreement to the extent the requisite approval of the Arrangement by the Corporation Shareholders has not already been obtained or any such approval is otherwise necessary or reasonably desirable in connection with the completion of the Arrangement or any transactions or steps to be completed in connection therewith.

        NOW THEREFORE, in consideration of the promises and mutual covenants and agreements set forth herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged by the parties hereto, the parties hereto agree as follows:

1.    Covenants of the Securityholder

        The Securityholder hereby covenants and agrees in favour of the Purchaser that, until termination of this Support Agreement in accordance with Section 5 below, the Securityholder shall:

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2.    Representations and Warranties of the Securityholder

        The Securityholder hereby represents and warrants to the Purchaser and acknowledges that the Purchaser is relying upon such representations and warranties in entering into this Support Agreement and the Arrangement Agreement, that:

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3.    Capital Power Corporation

        CPC acknowledges the terms and conditions of this Support Agreement and covenants and agrees in favour of the Purchaser that CPC shall on and after the date of this Support Agreement and until this Support Agreement is terminated in accordance with Section 5 below: (i) cause the Securityholder to fulfill and comply with all of its obligations hereunder, (ii) unless otherwise agreed to in writing with the Purchaser, not make a Partnership Acquisition Proposal or a Corporation Acquisition Proposal, and (iii) ensure that its Subsidiaries (which, for greater certainty, shall not include the Partnership Entities or any Partnership Subsidiary), officers, directors and key employees and any financial advisors or other advisors, representatives or agents retained by it are aware of the provisions of this Section 3, and shall be responsible for any breach of this Section 3 by any such Subsidiaries, officers, directors and key employees and any financial advisors or other advisors, representatives or agents.

4.    Covenants of the Securityholder and CPC Regarding Non-Solicitation

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5.    Termination

        This Support Agreement and the parties' rights and obligations hereunder shall terminate and be of no further force or effect, and there shall be no obligation or further liability on the part of the Securityholder, CPC or the Purchaser hereunder, without any further action by the Securityholder, CPC or the Purchaser, upon the earlier of: (i) the Effective Time; or (ii) the time at which the Arrangement Agreement is terminated in accordance with its terms; provided, however, that no such termination of this Support Agreement shall relieve any party hereto from any liability for any breach of this Support Agreement prior to such termination (other than a breach of the representations and warranties set forth in Section 2(n) for which the Securityholder shall have no liability unless the Effective Time has occurred).

6.    Indemnification

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        If a Claim by a third Person is made against any Purchaser Indemnified Party, and if such Purchaser Indemnified Party intends to seek indemnity with respect thereto under this Section 6, such Purchaser Indemnified Party shall promptly notify the Securityholder of such Claim; provided that the failure to so notify shall not relieve the Securityholder of its obligations hereunder, except to the extent that the Securityholder is actually and materially prejudiced thereby. The Securityholder shall have 30 days after receipt of such notice to assume the conduct and control, through counsel reasonably acceptable to the Purchaser Indemnified Party at the expense of the Securityholder, of the settlement or defence thereof; provided that (a) the Securityholder shall permit the Purchaser Indemnified Party to participate in such settlement or defence through counsel chosen by such Purchaser Indemnified

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Party, provided that the fees and expenses of such counsel shall be borne by such Purchaser Indemnified Party, and (b) the Securityholder shall promptly be entitled to assume the defence of such action only to the extent the Securityholder acknowledges its indemnity obligation and assumes and holds such Purchaser Indemnified Party harmless from and against the full amount of any loss resulting therefrom; and provided further that the Securityholder shall not be entitled to assume control of such defence and shall pay the fees and expenses of counsel retained by the Purchaser Indemnified Party if: (i) the parties agree, reasonably and in good faith, that such third Person Claim would give rise to losses which are more than twice the amount indemnifiable by the Securityholder pursuant to this Section 6; (ii) the Claim for indemnification relates to or arises in connection with any criminal proceeding, action, indictment, allegation or investigation; (iii) the Claim seeks an injunction or equitable relief against the Purchaser Indemnified Party; (iv) the Purchaser Indemnified Party has been advised by counsel that a reasonable likelihood exists of a conflict of interest between the Securityholder and the Purchaser Indemnified Party; (v) the Purchaser Indemnified Party reasonably believes an adverse determination with respect to the action, lawsuit, investigation, proceeding or other claim giving rise to such Claim for indemnification would be detrimental to or injure the Purchaser Indemnified Party's reputation or future business prospects; or (vi) upon petition by the Purchaser Indemnified Party, the appropriate court rules that the Securityholder failed or is failing to vigorously prosecute or defend such claim. Any Purchaser Indemnified Party shall have the right to employ separate counsel in any such action or Claim and to participate in the defence thereof, but the fees and expenses of such counsel shall not be at the expense of the Securityholder unless (x) the Securityholder shall have failed, within a reasonable time after having been notified by the Purchaser Indemnified Party of the existence of such Claim as provided in the preceding sentence, to assume the defence of such Claim, (y) the employment of such counsel has been specifically authorized by the Securityholder, which authorization shall not be unreasonably withheld, conditioned or delayed, or (z) the named parties to any such action include both such Purchaser Indemnified Party and the Securityholder and such Purchaser Indemnified Party shall have been advised by such counsel that there may be one or more legal defences available to the Purchaser Indemnified Party which are not available to the Securityholder, or available to the Securityholder the assertion of which would be adverse to the interests of the Purchaser Indemnified Party. So long as the Securityholder is reasonably contesting any such Claim in good faith, the Purchaser Indemnified Party shall not pay or settle any such Claim. Notwithstanding the foregoing, the Purchaser Indemnified Party shall have the right to pay or settle any such Claim, provided that in such event it shall waive any right to indemnity therefor by the Securityholder for such Claim unless the Securityholder shall have consented to such payment or settlement. If the Securityholder does not notify the Purchaser Indemnified Party within 30 days after the receipt of the Purchaser Indemnified Party's notice of a Claim of indemnity hereunder that it elects to undertake the defence thereof, the Purchaser Indemnified Party shall have the right to contest, settle or compromise the Claim but shall not thereby waive any right to indemnity therefor pursuant to this Support Agreement. The Securityholder shall not, except with the consent of the Purchaser Indemnified Party, enter into any settlement that is not entirely indemnifiable by the Securityholder pursuant to this Section 6 and does not include as an unconditional term thereof the giving by the Person or Persons asserting such Claim to all Purchaser Indemnified Parties of an unconditional release from all liability with respect to such Claim or consent to entry of any judgment. Notwithstanding any of the foregoing, in the event that it is reasonably foreseeable that the amount of any loss to be incurred by the Purchaser Indemnified Party with respect to any third Person Claim is more than twice the amount indemnifiable by the Securityholder, the Purchaser Indemnified Party shall be entitled to conduct and control the defence and/or settlement of any such Claim without the consent of the Securityholder. The Securityholder and the Purchaser Indemnified Party shall cooperate with each other in all reasonable respects in connection with the defence of any Claim, including making available records relating to such Claim and furnishing, without expense to the Securityholder and/or its counsel, such employees of the Purchaser Indemnified Party as may be reasonably necessary for the preparation of the defence of any such Claim or for testimony as witnesses in any proceeding relating to such claim.

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        The obligation of the Securityholder to indemnify the Purchaser Indemnified Parties pursuant to this Section 6 shall also be subject to the following:

        The rights of indemnification contained in this Section 6 are cumulative and are in addition to every other right or remedy of the Purchaser Indemnified Parties contained in this Support Agreement or otherwise.

        All indemnification payments payable hereunder shall be reduced by the amount of insurance proceeds actually received by the Purchaser Indemnified Party for such loss for which the Purchaser Indemnified Party is seeking indemnification.

7.    Covenant of the Purchaser Regarding Change of Name

        The Purchaser hereby covenants and agrees in favour of the Securityholder and CPC that, within the later of 30 days following the termination of the Transitional Services Agreement or 180 days following the Effective Date, the Purchaser shall use commercially reasonable efforts to cause each of the Partnership Entities and each of the Partnership Subsidiaries to change its name to a name that does not include "Capital Power", "CPI" or "CP" and the Purchaser shall, and shall cause each of its Subsidiaries and Affiliates, including the Partnership Entities and the Partnership Subsidiaries, to, (i) cease to use the names "Capital Power", "CPI" or "CP" or any associated trademarks or designs, (ii) cease to use any software, web pages and domain names containing references to "Capital Power", "CPI" or "CP", (iii) remove or cause to be removed all references to "Capital Power", "CPI" or "CP" and any associated trademarks or designs from all buildings, letterhead, signage, software and web pages used in connection with the business of the Purchaser and its Subsidiaries and Affiliates, including the Partnership Entities and the Partnership Subsidiaries.

8.    Restrictions on Sales of Purchaser Shares by the Securityholder

        During the period commencing on the Effective Date and ending on the date that is 90 days after the Effective Date, the Securityholder shall not, directly or indirectly, without the prior written consent of the Purchaser, such consent not to be unreasonably withheld, offer, sell, negotiate or enter into any agreement to offer, sell, pledge, grant any option to purchase, hedge, transfer, assign, make any short sale or otherwise dispose of any Purchaser Shares received pursuant to the Arrangement (or agree to,

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or announce, any intention to do so), except for a transfer of such Purchaser Shares (a) to an Affiliate of the Securityholder, provided such Affiliate remains as such and agrees to be bound by the restrictions in this Section 8 or (b) in accordance with and subject to the terms and conditions of a formal take-over bid or similar acquisition transaction, reorganization, plan of arrangement or merger.

9.    Entire Agreement and Amendment

        This Support Agreement, including the schedules hereto, constitutes the entire agreement, and supersedes all other prior agreements and understandings, both written and oral, between the parties and may not be modified, amended, altered or supplemented except upon the execution and delivery of a written agreement executed by each of the parties hereto.

10.    Assignment

        No party to this Support Agreement may assign this Support Agreement or any of its rights or obligations hereunder without the prior written consent of the other party.

11.    Enurement

        This Support Agreement shall be binding upon and shall enure to the benefit of and be enforceable by the Securityholder, the Purchaser and their respective successors and permitted assigns.

12.    Amendments to Arrangement Agreement

        In the event that the Arrangement Agreement is amended, modified, restated, replaced or superseded from time to time, all references herein to the Arrangement Agreement shall be to the Arrangement Agreement as so amended, modified or restated from time to time or to the agreement that has replaced or superseded it from time to time.

13.    Disclosure

        None of the parties hereto shall disclose the existence of this Support Agreement, or any details hereof, to any Person other than the Purchaser, the Securityholder, CPC, the Partnership, GP or the Corporation and their respective directors, officers and advisors, without the prior written consent of the other parties hereto, except in any news release announcing the Arrangement issued in accordance with the terms and conditions of the Arrangement Agreement or as required by applicable Law or legal process, including without limitation, any such Law in respect of the Partnership Circular, the Purchaser Circular, the Form S-4, any documents prepared in connection with the Purchaser financing (including in respect of the Bridge Loans) related to the Proposed Transaction, court documents prepared in respect of the Arrangement and other public disclosure of this Support Agreement which may be required under applicable Law.

14.    Notices

        All notices and other communications given or made pursuant hereto shall be in writing and shall be deemed to have been duly given or made as of the date delivered or sent if delivered personally or sent by facsimile or e-mail transmission, or as of the following Business Day if sent by prepaid overnight courier, to the parties at the following addresses (or at such other addresses as shall be specified by any party by notice to the other given in accordance with these provisions):

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15.    Governing Law

        This Support Agreement shall be governed, including as to validity, interpretation and effect, by the laws of the Province of Alberta and the federal laws of Canada applicable therein, and shall be construed and treated in all respects as an Alberta contract. Each of the parties hereby irrevocably attorns to the non-exclusive jurisdiction of the Courts in the Province of Alberta in respect of all matters arising under and in relation to this Support Agreement.

16.    Time of the Essence

        Time shall be of the essence of this Support Agreement.

17.    Remedies

        Each of the Securityholder and CPC acknowledges and agrees that this Support Agreement is an integral part of the transactions contemplated under the Arrangement Agreement, that the Purchaser would not enter into the Arrangement Agreement unless this Support Agreement is executed and delivered, and accordingly acknowledges and agrees that in the event of any breach or threatened breach by any of the Securityholder or CPC of this Support Agreement monetary damages will be an inadequate remedy, and without limiting any other remedies available to the Purchaser, whether at law, in equity or otherwise, the Purchaser shall be entitled, without the requirement of posting a bond or any other security, to equitable relief, including, without limitation, injunctive or similar relief to restrain the breach (actual or threatened) or any continuation thereof, and to require specific performance of the provisions hereof. After the Effective Time, the rights of indemnity under Section 6 of this Support Agreement shall be the exclusive monetary remedy of the Purchaser under this Support Agreement, but are not, for clarity, the exclusive monetary remedy under any other documents or agreements delivered in connection with the Proposed Transaction or the Arrangement Agreement (and the transactions contempleted thereby). Notwithstanding the foregoing, the limits described in this paragraph shall not apply to any Claims arising with respect to (a) fraud or (b) willful or intentional misconduct.

18.    Further Assurances

        Each of the Securityholder and CPC shall from time to time and at all times hereafter at the request of the Purchaser, acting reasonably, but without further consideration, do and perform such further acts and sign and deliver such further documents and give such further assurances as the Purchaser may reasonably request for the purpose of giving effect to this Support Agreement, including, without limitation, cooperating in good faith and taking all commercially reasonable steps and actions after the date hereof, as are not adverse to the party requested to take any such step or action, to complete the Proposed Transaction.

19.    Expenses

        Each of the Purchaser, CPC and the Securityholder agrees to pay its own respective costs and expenses incurred in connection with the preparation, execution and delivery of this Support Agreement and all documents and instruments executed or prepared pursuant hereto.

20.    Counterpart Execution

        This Support Agreement may be signed in counterparts that together shall be deemed to constitute one and the same instrument, and delivery of such counterparts may be effected by means of facsimile or other electronic transmission.

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        If you are in agreement with the foregoing, please indicate your acceptance thereof by signing and returning this letter to the Purchaser.

  Yours truly,

 

ATLANTIC POWER CORPORATION

 

Per:

 



      Name:
Title:
Address:
Facsimile:
Email:

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ACCEPTANCES

        For good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the undersigned Securityholder hereby irrevocably accepts and agrees to the foregoing terms and conditions of this Support Agreement as of the 20th day of June, 2011.

  CAPITAL POWER L.P., by its general partner,

 

CAPITAL POWER GP HOLDINGS INC.

 

Per:

 



      Name:
Title:
Address:
Facsimile:
Email:

        Capital Power Corporation acknowledges and agrees with the terms and conditions of this Support Agreement and executes this Support Agreement for the purposes of Sections 3, 4, 5 and 7 to 20 as of the 20th day of June, 2011.

  CAPITAL POWER CORPORATION

 

Per:

 



      Name:
Title:

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SCHEDULE 2(o)

Equipment/Personal Property

1.
Personal computers owned by CPC and/or its Subsidiaries and used by the Partnership Entities and the Partnership Subsidiaries.

2.
Microsoft software EA licenses held by CPC.

3.
Use of the name "Capital Power", "CPI" and "CP".

4.
Permits and Licenses disclosed in Schedule 3.1(j) to the Partnership Entities Disclosure Letter.

5.
Certain Contracts disclosed in Schedule 3.1(c) to the Partnership Entities Disclosure Letter.

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LOGO


SUPPORT AGREEMENT

June 20, 2011

TO:    EPCOR UTILITIES INC.

Dear Sir/Madam:

Re:
Proposed Acquisition by Atlantic Power Corporation (the "Purchaser") of Capital Power Income L.P. (the "Partnership") and CPI Investments Inc. (the "Corporation")

        Reference is made to the Arrangement Agreement dated as of the date hereof (the "Arrangement Agreement") among the Purchaser, the Partnership, CPI Income Services Ltd., and the Corporation regarding the proposed acquisition of the Partnership and the Corporation by the Purchaser pursuant to a plan of arrangement under the Canada Business Corporations Act on the terms and conditions set out in the Arrangement Agreement (the "Proposed Transaction"). The entering into of the Arrangement Agreement by the Purchaser is subject to, among other things, the execution and delivery of this Support Agreement and the approval of the Arrangement by the Corporation Shareholders.

        All capitalized terms and phrases used in this Support Agreement but not defined herein shall have the respective meanings given to them in Schedule "A" hereto.

        The purpose of this Support Agreement is to confirm the commitment of the undersigned securityholder of the Corporation (the "Securityholder") to vote or cause to be voted at any meeting of holders of the Corporation Shares, including any adjournment or postponement thereof, or in any other circumstances (including by way of written resolution) upon which a vote, consent or other approval with respect to the special resolution and/or any other resolution to approve the Arrangement and any ancillary matters required to give legal effect to the foregoing is sought (the "Corporation Transaction Approvals"), all Corporation Shares owned (beneficially or otherwise) by the Securityholder, directly or indirectly, or over which the Securityholder exercises control or direction (collectively, the "Subject Securities"), in favour of the Arrangement and to otherwise support the Proposed Transaction on the terms and conditions of this Support Agreement to the extent the requisite approval of the Arrangement by the Corporation Shareholders has not already been obtained or any such approval is otherwise necessary or reasonably desirable in connection with the completion of the Arrangement or any transactions or steps to be completed in connection therewith.

        NOW THEREFORE, in consideration of the promises and mutual covenants and agreements set forth herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged by the parties hereto, the parties hereto agree as follows:

1.     Covenants of the Securityholder

        The Securityholder hereby covenants and agrees in favour of the Purchaser that, until termination of this Support Agreement in accordance with Section 4 below, the Securityholder shall:

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2.     Representations and Warranties of the Securityholder

        The Securityholder hereby represents and warrants to the Purchaser and acknowledges that the Purchaser is relying upon such representations and warranties in entering into this Support Agreement and the Arrangement Agreement, that:

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3.     Covenants of the Securityholder Regarding Non-Solicitation

4.     Termination

        This Support Agreement and the parties' rights and obligations hereunder shall terminate and be of no further force or effect, and there shall be no obligation or further liability on the part of the Securityholder or the Purchaser hereunder, upon the earlier of: (i) without any further action by the Securityholder or the Purchaser, the Effective Time; or (ii) the time at which the Arrangement Agreement is terminated in accordance with its terms; provided, however, that no such termination of this Support Agreement shall relieve any party hereto from any liability for any breach of this Support Agreement prior to such termination.

5.     Entire Agreement and Amendment

        This Support Agreement, including the schedules hereto, constitutes the entire agreement, and supersedes all other prior agreements and understandings, both written and oral, between the parties and may not be modified, amended, altered or supplemented except upon the execution and delivery of a written agreement executed by each of the parties hereto.

6.     Assignment

        No party to this Support Agreement may assign this Support Agreement or any of its rights or obligations hereunder without the prior written consent of the other party.

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7.     Enurement

        This Support Agreement shall be binding upon and shall enure to the benefit of and be enforceable by the Securityholder, the Purchaser and their respective successors and permitted assigns.

8.     Amendments to Arrangement Agreement

        In the event that the Arrangement Agreement is amended, modified, restated, replaced or superseded from time to time, all references herein to the Arrangement Agreement shall be to the Arrangement Agreement as so amended, modified or restated from time to time or to the agreement that has replaced or superseded it from time to time.

9.     Disclosure

        None of the parties hereto shall disclose the existence of this Support Agreement, or any details hereof, to any Person other than the Purchaser, the Partnership, GP, the Securityholder or the Corporation and their respective directors, officers and advisors, without the prior written consent of the other parties hereto, except in any news release announcing the Arrangement issued in accordance with the terms and conditions of the Arrangement Agreement or as required by applicable Law or legal process, including without limitation, any such Law in respect of the Partnership Circular, the Purchaser Circular, the Form S-4, any documents prepared in connection with any Purchaser financing (including any bridge loans) related to the Proposed Transaction, court documents prepared in respect of the Arrangement and other public disclosure of this Support Agreement which may be required under applicable Law.

        Notwithstanding the above, the Securityholder may disclose the existence of this Support Agreement and details hereof to (a) its directors, officers, employees and advisors who have a business need to know such, and (b) if required by applicable Law or other contractual obligation, its shareholder, the City of Edmonton, provided that in all instances, the Securityholder shall advise each person to whom information is disclosed, of the requirement for such information to remain confidential in accordance with the above terms and, in the case of (a), remain responsible for any disclosure contrary to these terms.

10.   Notices

        All notices and other communications given or made pursuant hereto shall be in writing and shall be deemed to have been duly given or made as of the date delivered or sent if delivered personally or sent by facsimile or e-mail transmission, or as of the following Business Day if sent by prepaid overnight courier, to the parties at the following addresses (or at such other addresses as shall be specified by any party by notice to the other given in accordance with these provisions):

11.   Governing Law

        This Support Agreement shall be governed, including as to validity, interpretation and effect, by the laws of the Province of Alberta and the federal laws of Canada applicable therein, and shall be construed and treated in all respects as an Alberta contract. Each of the parties hereby irrevocably attorns to the non-exclusive jurisdiction of the Courts in the Province of Alberta in respect of all matters arising under and in relation to this Support Agreement.

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12.   Time of the Essence

        Time shall be of the essence of this Support Agreement.

13.   Remedies

        The Securityholder acknowledges and agrees that this Support Agreement is an integral part of the transactions contemplated under the Arrangement Agreement, that the Purchaser would not enter into the Arrangement Agreement unless this Support Agreement is executed and delivered, and accordingly acknowledges and agrees that in the event of any breach or threatened breach by the Securityholder of this Support Agreement monetary damages will be an inadequate remedy, and without limiting any other remedies available to the Purchaser, whether at law, in equity or otherwise, the Purchaser shall be entitled, without the requirement of posting a bond or any other security, to equitable relief, including, without limitation, injunctive or similar relief to restrain the breach (actual or threatened) or any continuation thereof, and to require specific performance of the provisions hereof.

14.   Further Assurances

        The Securityholder shall from time to time and at all times hereafter at the request of the Purchaser, acting reasonably, but without further consideration, do and perform such further acts and sign and deliver such further documents and give such further assurances as the Purchaser may reasonably request for the purpose of giving effect to this Support Agreement, including, without limitation, cooperating in good faith and taking all commercially reasonable steps and actions after the date hereof, as are not adverse to the party requested to take any such step or action, to complete the Proposed Transaction.

15.   Expenses

        Each of the Purchaser and the Securityholder agrees to pay its own respective costs and expenses incurred in connection with the preparation, execution and delivery of this Support Agreement and all documents and instruments executed or prepared pursuant hereto.

16.   Counterpart Execution

        This Support Agreement may be signed in counterparts that together shall be deemed to constitute one and the same instrument, and delivery of such counterparts may be effected by means of facsimile or other electronic transmission.

17.   Meaning of "Knowledge"

        Where this Support Agreement makes reference to the "knowledge of the Securityholder" or similar terms, such shall mean only the actual knowledge of Dana Bissoondatt, Senior Legal Counsel, and Don Gerke, Director, Regulatory, and specifically excludes any obligation of inquiry to third-party advisors including outside legal counsel.

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        If you are in agreement with the foregoing, please indicate your acceptance thereof by signing and returning this letter to the Purchaser.


    Yours truly,

 

 

ATLANTIC POWER CORPORATION

 

 

Per:

 


 
        Name:
Title:
Address:
Facsimile:
Email:


ACCEPTANCE

        For good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the undersigned Securityholder hereby irrevocably accepts and agrees to the foregoing terms and conditions of this Support Agreement as of the 20th day of June, 2011.


    EPCOR UTILITIES INC.

 

 

Per:

 


 
        Name:
Title:
Address:
Facsimile:
Email:

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SCHEDULE "A"

DEFINITIONS

In the Support Agreement:

        "Affiliate" has the meaning ascribed thereto in the Securities Act (Alberta) and the rules, regulations and published policies made thereunder and, for greater certainty, in the case of the Partnership, the Corporation and GP, shall not include Primary Energy Recycling Corporation or Primary Energy Recycling Holdings LLC and any of their Affiliates;

        "Arrangement" means an arrangement under section 192 of the Canada Business Corporations Act on the terms and subject to the conditions set out in the Arrangement Agreement and in the Plan of Arrangement as supplemented, modified or amended in accordance with the terms of the Arrangement Agreement or the Plan of Arrangement or at the direction of the Court in the Final Order;

        "Arrangement Resolution" means the extraordinary resolution of the Partnership Unitholders in respect of the Arrangement to be considered by the Partnership Unitholders at the Partnership Meeting, substantially in the form and content of Schedule D to the Arrangement Agreement;

        "Authorization" means any authorization, sanction, ruling, declaration, filing, order, permit, approval, grant, licence, waiver, entitlement, classification, exemption, registration, consent, right, notification, condition, franchise, privilege, certificate, judgment, writ, injunction, award, determination, direction, decision, decree, bylaw, rule or regulation of any Governmental Entity;

        "Business Day" means any day other than a Saturday, Sunday or a statutory or civic holiday in the Province of Alberta or Ontario or the State of Massachusetts or New York;

        "Certificate of Arrangement" means the certificate to be issued by the Director pursuant to subsection 192(7) of the Canada Business Corporations Act giving effect to the Arrangement;

        "Corporation Acquisition Proposal" means a proposal or offer, oral or written, relating to any of the following (other than the transactions contemplated by the Arrangement Agreement or the Arrangement): (i) any merger, amalgamation, arrangement, share exchange, take-over bid, tender offer, recapitalization, consolidation, other business combination, liquidation or winding up directly or indirectly involving the Corporation, (ii) any sale or acquisition of beneficial ownership of any of the Corporation Shares, or (iii) any sale or acquisition of any Partnership Units owned by the Corporation or any exchange, mortgage, pledge, granting of any right or option to acquire or other arrangement involving the Partnership Units owned by the Corporation having similar economic effect;

        "Corporation Shares" means, collectively, the Class A Shares in the capital of the Corporation and the Class B Shares in the capital of the Corporation;

        "Court" means the Court of Queen's Bench of Alberta;

        "CPEL" means CPI Preferred Equity Ltd., a corporation incorporated under the Business Corporations Act (Alberta);

        "Director" means the Director or a Deputy Director appointed pursuant to section 260 of the Canada Business Corporations Act;

        "Distribution Agreement" means the distribution agreement to be entered into at the Effective Time among CPI Power Holdings Inc., New LLC, CPEL, the Partnership and the Purchaser in the form set forth in Schedule F to the Arrangement Agreement;

        "Effective Date" means the date shown on the Certificate of Arrangement, which date shall be determined in accordance with section 2.6 of the Arrangement Agreement;

        "Effective Time" has the meaning ascribed thereto in the Plan of Arrangement;

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        "Encumbrances" means any pledges, liens, charges, security interests, leases, title retention agreements, mortgages, hypothecs, statutory or deemed trusts, adverse rights or claims, easements, indentures, deeds of trust, rights of way, restrictions on use of real property, licences to third parties, leases to third parties, security agreements, assignments, or encumbrances of any kind or character whatsoever, whether contingent or absolute, and any agreement, option, right of first refusal, right or privilege (whether by Law, contract or otherwise) capable of becoming any of the foregoing;

        "Final Order" means the final order of the Court approving the Arrangement to be applied for by the Partnership, GP and the Corporation following the Partnership Meeting and to be granted pursuant to subsection 192(4) of the Canada Business Corporations Act in respect of the Partnership, GP and the Corporation, as such order may be affirmed, amended or modified by the Court (with the consent of each of the Partnership, GP, the Corporation and the Purchaser, each acting reasonably) at any time prior to the Effective Date or, if appealed, then, unless such appeal is withdrawn or denied, as affirmed or as amended (provided that such amendment is acceptable to each of the Partnership, GP, the Corporation and the Purchaser, each acting reasonably) on appeal;

        "Form S-4" means a registration statement on Form S-4 (or other applicable form) pursuant to which the Purchaser shall seek to register the Purchaser Share Issuance under the U.S. Securities Act;

        "GAAP" means the generally accepted accounting principles and practices in Canada, including the principles set forth in the Handbook published by the Canadian Institute of Charter Accountants, or any successor institute, which are applicable as at the date of the financial information in respect of which a calculation is made hereunder or as at the date of the particular financial statements referred to herein, as the case may be;

        "Governmental Entity" means any applicable (i) multinational, federal, provincial, state, regional, municipal, local or other government, governmental or public department, ministry, central bank, court, tribunal, arbitral body, commission, commissioner, board, bureau or agency, domestic or foreign, (ii) stock exchange, including each of the Toronto Stock Exchange and the New York Stock Exchange; (iii) subdivision, agent, or authority of any of the foregoing, or (iv) quasi-governmental or private body, including any tribunal, commission, regulatory agency or self-regulatory organization, exercising any regulatory, expropriation or taxing authority under or for the account of any of the foregoing;

        "GP" means CPI Income Services Ltd., and, for greater certainty, except where otherwise contemplated, means CPI Income Services Ltd. in its personal capacity and not as general partner of the Partnership;

        "IFRS" means the International Financial Reporting Standards as issued by the International Accounting Standards Board and adopted by the Canadian Institute of Chartered Accountants;

        "Law" or "Laws" means all laws, statutes, codes, ordinances, decrees, rules, regulations, by-laws, statutory rules, judicial or arbitral or administrative or ministerial or departmental or regulatory judgments, orders, decisions, rulings, injunctions, determinations, awards or other requirements, and terms and conditions of any permit, grant of approval, permission, authority or licence of any Governmental Entity, statutory body or self-regulatory authority (including the Toronto Stock Exchange and the New York Stock Exchange), and the term "applicable" with respect to such Laws and in the context that refers to one or more Persons, means that such Laws apply to such Person or Persons and/or its Subsidiaries or its or their business, undertaking, property, Benefit Plans (as defined in the Arrangement Agreement) or securities and emanate from a Governmental Entity having jurisdiction over the Person or Persons and/or its Subsidiaries or its or their business, undertaking or securities;

        "Material Adverse Effect" means, with respect to any Person(s), any change, effect, event, occurrence, fact, state of facts or development that, either individually is or in the aggregate are, or individually or in the aggregate would reasonably be expected to be, both material and adverse to the business, operations, results of operations, properties, assets, liabilities, obligations (whether accrued,

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conditional or otherwise) or condition (financial or otherwise) of such Person(s) and its Subsidiaries taken as a whole, other than any change, effect, event, occurrence, fact, state of facts or development:

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provided, however, that the change, effect, event, occurrence or state of facts or development referred to in clauses (a) to (e) above shall not be excluded from the definition of Material Adverse Effect in respect of any Person if it materially disproportionately adversely affects such Person and its Subsidiaries, taken as a whole, compared to other companies of similar size operating in the industry in which the Person and its Subsidiaries operate;

        "NC Purchase Agreement" means the membership interest purchase agreement dated June 20, 2011 between CPI USA Holdings LLC, CPI Power Holdings Inc. and Capital Power Investments LLC in the form set forth in Schedule G to the Arrangement Agreement;

        "New LLC" means the limited liability company to be established pursuant to the laws of the State of Delaware prior to the Effective Date and wholly-owned by CPI Power Holdings, Inc.;

        "New LLC2" means the limited liability company to be established pursuant to the laws of the State of Delaware prior to the Effective Date and wholly-owned by New LLC;

        "Partnership Acquisition Proposal" means a proposal or offer, oral or written, relating to any of the following (other than the transactions contemplated by the Arrangement Agreement or the Arrangement): (i) any take-over bid (including an acquisition of Partnership Units from the Corporation), tender offer or exchange offer that, if consummated, would result in any Person, or group of Persons or shareholders of such Person(s) beneficially owning 20% or more of any class of voting or equity securities of the Partnership; (ii) a plan of arrangement, merger, amalgamation, consolidation, share exchange, business combination, reorganization, recapitalization, liquidation,

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dissolution or other similar transaction involving the Partnership and/or the Partnership Subsidiaries whose assets or revenues, individually or in the aggregate, constitute 20% or more of the consolidated assets or revenues, as applicable, of the Partnership; (iii) any sale or acquisition, direct or indirect, of assets representing 20% or more of the consolidated assets or revenues of the Partnership or which contribute 20% or more of the consolidated revenues of the Partnership, or any lease, long-term supply agreement (other than in the ordinary course of business), exchange, mortgage, pledge or other arrangement having a similar economic effect, in a single transaction or a series of related transactions; or (iv) any sale or acquisition of beneficial ownership of 20% or more of the Partnership Units (or securities convertible or exchangeable into voting or equity securities of the Partnership) or 20% or more of the voting or equity securities of any of the Partnership Subsidiaries (or securities convertible or exchangeable into voting or equity securities of such Partnership Subsidiaries) whose assets, individually or in the aggregate, constitute 20% or more of the consolidated assets or revenues of the Partnership or which contribute 20% or more of the consolidated assets or revenues of the Partnership, or rights or interests therein or thereto in a single transaction or a series of related transactions;

        "Partnership Circular" means the notice of meeting and management information circular, including all schedules, appendices and exhibits thereto, to be prepared and mailed to the Partnership Unitholders in connection with the Partnership Meeting, as may be amended, supplemented or otherwise modified;

        "Partnership Entities" means the Partnership and GP;

        "Partnership Facilities" means the facilities in which the Partnership holds a direct or indirect interest, except for (i) the Partnership's Roxboro and Southport facilities located in the State of North Carolina, and (ii) any facilities owned, directly or indirectly, by PERH;

        "Partnership Meeting" means the special meeting of Partnership Unitholders, including any adjournment or postponement thereof, to be held to consider the Arrangement Resolution;

        "Partnership Reorganization Agreements" means the NC Purchase Agreement and the Distribution Agreement;

        "Partnership Subsidiaries" means all Subsidiaries of the Partnership, and which, for the purposes of this Agreement, shall not include CPI USA North Carolina LLC, New LLC, New LLC2, PERH or any Subsidiary of PERH;

        "Partnership Unitholders" means holders of Partnership Units;

        "Partnership Units" means the limited partnership units of the Partnership;

        "PERH" means Primary Energy Recycling Holdings LLC;

        "Person" includes an individual, limited or general partnership, limited liability company, limited liability partnership, trust, joint venture, association, body corporate, unincorporated organization, trustee, executor, administrator, legal representative, government (including any Governmental Entity) or any other entity, whether or not having legal status;

        "Plan of Arrangement" means the plan of arrangement, substantially in the form and content of Schedule A attached to the Arrangement Agreement as such plan of arrangement may be amended or supplemented from time to time in accordance with the terms of the Plan of Arrangement and the Arrangement Agreement;

        "Purchaser Circular" means the notice of meeting and management information circular, including all schedules, appendices and exhibits thereto, to be prepared and mailed to the Purchaser Shareholders in connection with the Purchaser Meeting, as may be amended, supplemented or otherwise modified;

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        "Purchaser Meeting" means the special meeting of Purchaser Shareholders, including any adjournment or postponement thereof, to consider the Purchaser Share Issuance Resolution;

        "Purchaser Share Issuance" means the issuance of Purchaser Shares pursuant to the Arrangement;

        "Purchaser Share Issuance Resolution" means the ordinary resolution approving the issuance of the Purchaser Shares pursuant to the Arrangement, in accordance with the requirements of the Toronto Stock Exchange and New York Stock Exchange, to be considered by the Purchaser Shareholders at the Purchaser Meeting;

        "Purchaser Shareholders" means the holders of the Purchaser Shares;

        "Purchaser Shares" means the common shares in the capital of the Purchaser;

        "Subsidiary" has the meaning ascribed thereto in National Instrument 45-106—Prospectus and Registration Exemptions;

        "U.S. GAAP" means accounting principles generally accepted in the United States of America; and

        "U.S. Securities Act" means the United States Securities Act of 1933, as amended.

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SCHEDULE "B"

SHAREHOLDERS AGREEMENT

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SCHEDULE F

FORM OF DISTRIBUTION AGREEMENTS

[New LLC]

—and—

CPI POWER HOLDINGS INC.

—and—

CPI PREFERRED EQUITY LTD.

—and—

CAPITAL POWER INCOME L.P.

—and—

ATLANTIC POWER CORPORATION



DISTRIBUTION AGREEMENT



                        , 2011

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TABLE OF CONTENTS

ARTICLE 1 INTERPRETATION

  Annex A-158  
 

1.1

 

Definitions

  Annex A-158  
 

1.2

 

Additional Rules of Interpretation

  Annex A-158  

ARTICLE 2 Distributions AND TRANSACTION SEQUENCE

 
Annex A-159
 
 

2.1

 

Time of Transactions

  Annex A-159  
 

2.2

 

First Distribution

  Annex A-159  
 

2.3

 

Exchange

  Annex A-159  
 

2.4

 

PEL Loan

  Annex A-160  
 

2.5

 

CPILP Debt Repayment

  Annex A-160  
 

2.6

 

Effect of Distributions and Transactions

  Annex A-160  
 

2.7

 

Approvals

  Annex A-160  

ARTICLE 3 GENERAL

 
Annex A-160
 
 

3.1

 

Further Assurances

  Annex A-160  
 

3.2

 

Notices

  Annex A-160  
 

3.3

 

Governing Law; Attornment

  Annex A-162  
 

3.4

 

Amendment

  Annex A-163  
 

3.5

 

Assignment

  Annex A-163  
 

3.6

 

Waiver

  Annex A-163  
 

3.7

 

Severability

  Annex A-163  
 

3.8

 

Time of the Essence

  Annex A-163  
 

3.9

 

Costs and Expenses

  Annex A-163  
 

3.10

 

Enurement

  Annex A-163  
 

3.11

 

Counterparts

  Annex A-163  
 

3.12

 

Third Parties

  Annex A-164  
 

3.13

 

Automatic Termination

  Annex A-164  
 

3.14

 

English Language

  Annex A-164  

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DISTRIBUTION AGREEMENT

THIS AGREEMENT dated this                day of                            , 2011,

BETWEEN:

[New LLC]

—and—

CPI POWER HOLDINGS INC

—and—

CPI PREFERRED EQUITY LTD.

—and—

CAPITAL POWER INCOME L.P.

—and—

ATLANTIC POWER CORPORATION

WHEREAS:

A.
CPILP, CPI Income Services Ltd., CPI Investments Inc. and the Purchaser have entered into an arrangement agreement dated June 20, 2011 pursuant to which the Purchaser has agreed to acquire, directly or indirectly, all of the issued and outstanding limited partnership units of CPILP and shares of CPI Investments Inc. pursuant to a plan of arrangement (the "Arrangement").

B.
CPIU, CPIH and CPIL have entered into an agreement (the "Membership Interest Purchase Agreement") dated June 20, 2011.

C.
The rights of CPIU as seller pursuant to the Membership Interest Purchase Agreement have been assigned to New LLC.

D.
Pursuant to the Membership Interest Purchase Agreement, New LLC has agreed to sell its membership interests in New LLC2 to CPIL in consideration for the amount of Cdn$121,405,211 (the "Funds") to be paid by CPIL to New LLC.

E.
All of the membership interests of New LLC are directly owned by CPIH. In connection with the Arrangement, New LLC proposes to distribute the Funds to CPIH as a membership distribution (the "First Distribution"). As a result of the First Distribution, CPIH will be entitled to receive the Funds.

F.
The preferred membership interests of Power USA are jointly held by CPIH, as to US$25 million, and PEL, as to US$285 million (the "Preferred Membership Interests"). CPIH proposes to acquire US$    •    Preferred Membership Interests [insert US dollar equivalent to the Cdn dollar amount of the Funds on date of execution] held by PEL in consideration for the transfer of the Funds from CPIH to PEL (the "Exchange"). As a result of the Exchange, PEL will be entitled to receive the Funds.

G.
PEL proposes to loan the Funds to CPILP on an interest-free basis (the "PEL Loan"). As a result of the PEL Loan, CPILP will be entitled to receive the Funds.

H.
CPILP has outstanding indebtedness to certain creditors under certain credit facilities in the amount of Cdn$    •    (the "CPILP Indebtedness"), which amount includes all interest and additional amounts payable to such creditors in order to settle fully such indebtedness. CPILP proposes to repay and settle the CPILP Indebtedness in full by transferring and assigning a portion

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I.
The purpose of this Agreement is for the Parties to acknowledge and agree upon the sequence of the distributions and other transactions set forth herein.

        NOW THEREFORE in consideration of the mutual covenants set forth herein, the Parties hereby agree as follows:


ARTICLE 1
INTERPRETATION

1.1  Definitions

        Capitalized terms not otherwise defined herein shall have the meanings given in the Arrangement Agreement. As used in this Agreement, the following terms have the respective meanings given below.

        "Agreement" means this Distribution Agreement, as the same may be amended, supplemented or otherwise modified from time to time;

        "Arrangement Agreement" means the Arrangement Agreement made as of June 20, 2011 among Capital Power Income L.P., CPI Income Services Ltd., CPI Investments Inc. and the Purchaser;

        "CPIH" means CPI Power Holdings Inc.;

        "CPIL" means Capital Power Investments LLC;

        "CPILP" means Capital Power Income L.P.;

        "CPIU" means CPI USA Holdings LLC;

        "Depositary" means Computershare Investor Services Inc.

        "New LLC" means [newly formed subsidiary of CPIH];

        "New LLC2" means [newly formed subsidiary of New LLC];

        "Parties" means New LLC, CPIH, PEL, CPILP and the Purchaser, each individually referred to as a "Party";

        "PEL" means "CPI Preferred Equity Ltd.;

        "Power USA" means CPI Power USA LLC;

        "Purchaser" means Atlantic Power Corporation;

1.2  Additional Rules of Interpretation

        For purposes of this Agreement, unless otherwise specified in the Arrangement:

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ARTICLE 2
Distributions AND TRANSACTION SEQUENCE

2.1  Time of Transactions

        The transactions described in Sections 2.2 to 2.5 will occur in the order set out in this Agreement and at the time specified under the Arrangement.

2.2  First Distribution

        New LLC will transfer and assign the Funds to CPIH by way of a return of capital and CPIH will accept the Funds from New LLC.

2.3  Exchange

        Effective immediately after the First Distribution CPIH will, pursuant to the terms of the Sale and Repurchase Agreement between PEL and CPIH dated September 28, 2007, transfer the Funds to PEL in consideration for the purchase of US$    •    Preferred Membership Interests in Power USA and PEL will transfer and assign such Preferred Membership Interests to CPIH.

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2.4  PEL Loan

        Effective immediately after the Exchange PEL will advance the Funds to CPILP in consideration for the issuance of a non-interest bearing demand promissory note of CPILP made in favour of PEL.

2.5  CPILP Debt Repayment

        Effective immediately after PEL makes the PEL Loan, CPILP will transfer Cdn$    •    of the Funds to certain of its creditors in full repayment of the CPILP Indebtedness, and will retain the Residual Funds.

2.6  Effect of Distributions and Transactions

        Each of the parties hereto hereby acknowledges and agrees that the flow of funds in the context of the First Distribution, the Exchange, the PEL Loan and the CPILP Debt Repayment will take place in the manner set out above, directs the relevant party to hold and transfer such funds in accordance with the directions set out above and, as applicable, agrees to hold or transfer the funds in accordance with such instructions.

        Prior to the closing of the sale of the membership interests in New LLC2 to CPIL, CPIL shall deposit the Funds with the Depositary. In connection with the sale of the membership interests in New LLC2 to CPIL, New LLC and CPIL shall direct the Depositary to transfer Cdn$    •    of the Funds to [insert name(s) repayment agent for CPILP Indebtedness] and to transfer the Residual Funds to CPILP (or as directed by CPILP).

        As a result of, and after giving effect to, the transactions set forth in paragraphs 2.2 through 2.5 above CPILP will be entitled to the Residual Funds.

2.7  Approvals

        Each of the Parties acknowledge and agree that all internal corporate approvals as may be required to effect the transactions contemplated in Sections 2.2 through 2.5 have been obtained.


ARTICLE 3
GENERAL

3.1  Further Assurances

        Each Party hereto shall, from time to time and at all times hereafter, at the request of the other Party hereto, but without further consideration, do all such further acts, and execute and deliver all such further documents and instruments and provide all such further assurances as may be reasonable required in order to fully perform and carry out the terms and intent hereof.

3.2  Notices

        All notices and other communications given or made pursuant hereto shall be in writing and shall be deemed to have been duly given or made as of the date delivered or sent if delivered personally or sent by facsimile or e-mail transmission, or as of the following Business Day if sent by prepaid

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overnight courier, to the Parties at the following addresses (or at such other addresses as shall be specified by any Party by notice to the other given in accordance with these provisions):

(a)   if to [New LLC]:

 

 

5th Floor, TD Tower
10088 - 102 Avenue
Edmonton, AB T5J 2Z1

 

 

Attention:

 

Senior Vice President, General Counsel & Corporate Secretary
    Facsimile No.:   (780) 392-5200
    Email:   kchisholm@capitalpower.com

 

 

with a copy (which shall not constitute notice) to:

 

 

Fraser Milner Casgrain LLP
15th Floor, Bankers Court
850 - 2nd Street S.W.
Calgary, AB T2P 0R8

 

 

Attention:

 

Bill Gilliland
    Facsimile No.:   (403) 268-3100
    Email:   bill.gilliland@fmc-law.com

(b)

 

if to CPIH:

 

 

5th Floor, TD Tower
10088 - 102 Avenue
Edmonton, AB T5J 2Z1

 

 

Attention:

 

Senior Vice President, General Counsel & Corporate Secretary
    Facsimile No.:   (780) 392-5200
    Email:   kchisholm@capitalpower.com

 

 

with a copy (which shall not constitute notice) to:

 

 

Fraser Milner Casgrain LLP
15th Floor, Bankers Court
850 - 2nd Street S.W.
Calgary, AB T2P 0R8

 

 

Attention:

 

Bill Gilliland
    Facsimile No.:   (403)268-3100
    Email:   bill.gilliland@fmc-law.com

(c)

 

if to PEL:

 

 

5th Floor, TD Tower
10088 - 102 Avenue
Edmonton, AB T5J 2Z1

 

 

Attention:

 

Senior Vice President, General Counsel & Corporate Secretary
    Facsimile No.:   (780) 392-5200
    Email:   kchisholm@capitalpower.com

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with a copy (which shall not constitute notice) to:

 

 

Fraser Milner Casgrain LLP
15th Floor, Bankers Court
850 - 2nd Street S.W.
Calgary, AB T2P 0R8

 

 

Attention:

 

Bill Gilliland
    Facsimile No.:   (403)268-3100
    Email:   bill.gilliland@fmc-law.com

(d)

 

if to CPILP:

 

 

5th Floor, TD Tower
10088 - 102 Avenue
Edmonton, AB T5J 2Z1

 

 

Attention:

 

Senior Vice President, General Counsel & Corporate Secretary
    Facsimile No.:   (780) 392-5200
    Email:   kchisholm@capitalpower.com

 

 

with a copy (which shall not constitute notice) to:

 

 

Fraser Milner Casgrain LLP
15th Floor, Bankers Court
850 - 2nd Street S.W.
Calgary, AB T2P 0R8

 

 

Attention:

 

Bill Gilliland
    Facsimile No.:   (403)268-3100
    Email:   bill.gilliland@fmc-law.com

(e)

 

if to Purchaser:

 

 

Atlantic Power Corporation
200 Clarendon Street, 25th Floor
Boston, MA 02116
USA

 

 

Attention:

 

Barry Welch
    Facsimile No.:   (617) 977-2410
    E-mail:   bwelch@atlanticpower.com

 

 

with a copy (which shall not constitute notice) to:

 

 

Goodmans LLP
Bay Adelaide Centre
333 Bay Street, Suite 3400
Toronto, ON M5H 2S7

 

 

Attention:

 

Bill Gorman
    Facsimile No.:   (416) 979-1234
    E-mail:   bgorman@goodmans.ca

3.3  Governing Law; Attornment

        This Agreement shall be governed, including as to validity, interpretation and effect, by the laws of the Province of Alberta and the federal laws of Canada applicable therein, and shall be construed and

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treated in all respects as an Alberta contract. Each of the Parties hereby irrevocably attorns to the exclusive jurisdiction of the Courts in the Province of Alberta in respect of all matters arising under and in relation to this Agreement and the Arrangement.

3.4  Amendment

        This Agreement may not be amended, supplemented or otherwise modified in any respect except by written instrument executed by the Parties.

3.5  Assignment

        This Agreement may not be assigned by any Party without the prior written consent of the other Parties, which consent may not be unreasonably withheld.

3.6  Waiver

        Any waiver of, or consent to depart from, the requirements of any provision of this Agreement shall be effective only if it is in writing and signed by the Party giving it, and only in the specific instance and for the specific purpose for which it has been given. No failure on the part of any Party to exercise, and no delay in exercising, any right under this Agreement shall operate as a waiver of such right. No single or partial exercise of any such right shall preclude any other or further exercise of such right or the exercise of any other right.

3.7  Severability

        Any provision in this Agreement which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof or affecting the validity or enforceability of such provision in any other jurisdiction.

3.8  Time of the Essence

        Time shall be of the essence of this Agreement.

3.9  Costs and Expenses

        Each Party shall be responsible for all costs and expenses (including the fees and disbursements of legal counsel, bankers, investment bankers, accountants, brokers and other advisors) incurred by it in connection with this Agreement and the transactions contemplated herein.

3.10  Enurement

        This Agreement shall enure to the benefit of and be binding upon the Parties and their respective heirs, executors, administrators, successors and permitted assigns, as the case may be.

3.11  Counterparts

        This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument. The Parties shall be entitled to rely upon delivery of an executed facsimile or similar executed electronic copy of this Agreement, and such facsimile or similar executed electronic copy shall be legally effective to create a valid and binding agreement among the Parties.

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3.12  Third Parties

        Except as specifically set forth or referred to herein, nothing herein is intended or shall be construed to confer upon or give to any Person, other than the Parties and their respective successors and permitted assigns, any rights or remedies under or by reason of this Agreement.

3.13  Automatic Termination

        This Agreement shall automatically terminate without any action of any Party hereto upon the termination of the Arrangement Agreement or the Membership Interest Purchase Agreement.

3.14  English Language

        The parties confirm that it is their wish that this Agreement and any other documents delivered or given pursuant to this Agreement, including notices, have been and shall be in the English language only.

[The remainder of this page intentionally left blank]

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        IN WITNESS WHEREOF this Agreement has been executed by the Parties on the date first above written.

    [New LLC]

 

 

By:

 

  

        Name:    
        Title:    

 

 

By:

 

 

        Name:    
        Title:    

 

 

CPI POWER HOLDINGS INC.

 

 

By:

 

  

        Name:    
        Title:    

 

 

By:

 

  

        Name:    
        Title:    

 

 

CPI PREFERRED EQUITY LTD.

 

 

By:

 

 

        Name:    
        Title:    

 

 

By:

 

  

        Name:    
        Title:    

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    CAPITAL POWER INCOME L.P.
By:
CPI Income Services Ltd., its general partner

 

 

By:

 

  

        Name:    
        Title:    

 

 

By:

 

 

        Name:    
        Title:    

 

 

ATLANTIC POWER CORPORATION

 

 

By:

 

 

        Name:    
        Title:    

 

 

By:

 

  

        Name:    
        Title:    

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SCHEDULE J

FORMS OF PREFERRED SHARE GUARANTEES

AMONG:

        WHEREAS pursuant to the terms of this guarantee indenture (the "Guarantee") the Guarantor has agreed to guarantee in favour of the Holders (as defined below) the payment of the Preferred Share Obligations (as defined below), pursuant to the terms of the Series 1 Shares (as defined below);

        AND WHEREAS as at the date hereof, the Corporation has authorized for issuance up to 5,750,000 Series 1 Shares;

        AND WHEREAS all necessary acts and proceedings have been done and taken and all necessary resolutions have been passed to authorize the execution and delivery of this Guarantee and to make the same legal, valid and binding upon the Guarantor;

        AND WHEREAS the foregoing recitals are made as representations and statements of fact by the Guarantor and not by the Trustee;

        NOW THEREFORE THIS GUARANTEE WITNESSES that for good and valuable consideration (the receipt and sufficiency of which are hereby acknowledged by each of the parties), the parties hereto agree as follows:


ARTICLE 1
DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION

1.1   Definitions

        For all purposes of this Guarantee, except as otherwise expressly provided or unless the context otherwise requires:

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        The following terms shall have the following meanings:

        "ABCA" means the Business Corporations Act (Alberta);

        "affiliate" has the meaning ascribed thereto in National Instrument 45-106—Prospectus and Registration Exemptions.

        "Board of Directors" means the board of directors of the Guarantor or any duly authorized committee of that board.

        "Board Resolution" means a copy of a resolution certified by an officer of the Guarantor to have been duly passed by the Board of Directors and to be in full force and effect on the applicable date of such certification, and delivered to the Trustee.

        "Business Day" means each Monday, Tuesday, Wednesday, Thursday and Friday which is not a day on which banking institutions in the City of Calgary are authorized or obligated by law or executive order to close.

        "Corporate Trust Office" means the office of the Trustee, at which at any particular time its corporate trust business shall be principally administered, which office on the date of execution of this Guarantee is located at [600, 333 - 7th Avenue S.W. Calgary, Alberta, T2P 2Z1].

        "Event of Default" has the meaning specified in Section 4.2.

        "Guarantor Order" or "Guarantor Request" means a written request or order signed in the name of the Guarantor by an officer of the Guarantor, and delivered to the Trustee.

        "Holders" means, for so long as registration of interests in and transfers of the Series 1 Shares are made through the book-based system administered by CDS Clearing and Depository Services Inc., the beneficial holders of the Series 1 Shares from time to time, and upon termination of the registration of the Series 1 Shares through the book-based system, the registered holders of the Series 1 Shares from time to time, provided that, in determining whether the Holders of the requisite percentage of the aggregate Liquidation Amount of outstanding Series 1 Shares have given any request, notice, consent or waiver hereunder, "Holders" shall not include the Guarantor or any affiliate of the Guarantor.

        "Liquidation Amount" means, in respect of any Series 1 Shares, the amount due in respect of such share were the Corporation to involuntarily liquidate at the date of determination of the Liquidation Amount, and includes all accrued and unpaid dividends at the time of determination.

        "Officers' Certificate" means a certificate signed by an officer of the Guarantor, and delivered to the Trustee.

        "Opinion of Counsel" means a written opinion of counsel, who may be counsel for the Guarantor, including an employee of the Guarantor, and who shall be acceptable to the Trustee.

        "Person" means an individual, a corporation, a partnership, an association, a trust or any other entity or organization, including a government or political subdivision or an agency or instrumentality thereof.

        "Preferred Share Obligations" means all financial liabilities and obligations of the Corporation to the Holders in respect of the Series 1 Shares including or in respect of (i) any accrued and unpaid dividends on the Series 1 Shares, (ii) the Redemption Price and all accrued and unpaid dividends up to but excluding the date of redemption with respect to Series 1 Shares called for redemption, and (iii) the Liquidation Amount payable on the Series l Shares upon a voluntary or involuntary dissolution, liquidation or winding up of the Corporation, without regard to the amount of assets of the Corporation available for distribution.

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        "Redemption Price" means (i) $26.00 per Series 1 Share if the Series 1 Shares are redeemed on or after June 30, 2012, but before June 30, 2013; (ii) $25.75 per Series 1 Share if the Series 1 Shares are redeemed on or after June 30, 2013, but before June 30, 2014; (iii) $25.50 per Series 1 Share if the Series 1 Shares are redeemed on or after June 30, 2014, but before June 30, 2015; (iv) $25.25 per Series 1 Share if the Series 1 Shares are redeemed on or after June 30, 2015, but before June 30, 2016; and (v) $25.00 per Series 1 Share if the Series 1 Shares are redeemed thereafter.

        "Responsible Officer", when used with respect to the Trustee, means the chairman or any vice-chairman of the board of directors of the Trustee, the chairman or any vice-chairman of the executive committee of the board of directors of the Trustee, and the chairman of the trust committee, the president, any vice president, the secretary, any assistant secretary, the treasurer, any assistant treasurer, any trust officer or assistant trust officer, the controller or any assistant controller and any other officer of the Trustee customarily performing functions similar to those performed by any of the above-designated officers, and also means, with respect to a particular corporate trust matter, any other officer to whom such matter is referred because of his knowledge of and familiarity with the particular subject.

        "Senior Indebtedness" shall mean the principal of and the interest and premium (or any other amounts payable thereunder), if any, on:

unless in each case it is provided by the terms of the instrument creating or evidencing such indebtedness, liabilities or obligations that such indebtedness, liabilities or obligations are pari passu with or subordinate in right of payment to the Preferred Share Obligations.

        "Series 1 Shares" means the Cumulative Redeemable Preferred Shares, Series 1 of the Corporation.

1.2   Compliance Certificates and Opinions

        Upon any application or request by the Guarantor to the Trustee to take any action under any provision of this Guarantee, the Guarantor shall furnish to the Trustee an Officers' Certificate stating that all conditions precedent, if any, provided for in this Guarantee (including any covenant compliance with which constitutes a condition precedent) relating to the proposed action have been complied with and an Opinion of Counsel stating that in the opinion of such counsel all such conditions precedent, if any, have been complied with, except that in the case of any such application or request as to which the furnishing of such documents is specifically required by any provision of this Guarantee relating to such particular application or request, no additional certificate or opinion need be furnished.

        In addition to the foregoing, every certificate or opinion with respect to compliance with a covenant or condition provided for in this Guarantee (other than as otherwise specified herein) shall include:

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1.3   Form of Documents Delivered to Trustee

        In any case where several matters are required to be certified by, or covered by an opinion of, any specified Person, it is not necessary that all such matters be certified by, or covered by the opinion of, only one such Person, or that they be so certified or covered by only one document, but one such Person may certify or give an opinion with respect to some matters and one or more other such Persons as to other matters, and any such Person may certify or give an opinion as to such matters in one or several documents.

        Any certificate or opinion of an officer of the Guarantor may be based, insofar as it relates to legal matters, upon a certificate or opinion of, or representations by, counsel, unless such officer knows, or in the exercise of reasonable care should know that the certificate or opinion or representations with respect to the matters upon which his or her certificate or opinion is based are erroneous. Any such certificate or Opinion of Counsel may be based, insofar as it relates to factual matters, upon a certificate or opinion of, or representations by, an officer or officers of the Guarantor stating that the information with respect to such factual matters is in the possession of the Guarantor, unless such counsel knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to such matters are erroneous.

        Where any Person is required to make, give or execute two or more applications, requests, consents, certificates, statements, opinions or other instruments under this Guarantee, they may, but need not, be consolidated and form one instrument.

1.4   Acts of Holders

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1.5   Notices, Etc. to Trustee and Guarantor

        Any request, demand, authorization, direction, notice, consent, waiver or Act of Holders or other documents provided or permitted by this Guarantee to be made upon, given or furnished to, or filed with,

        Any delivery made or facsimile sent on a day other than a Business Day, or after 3:00 p.m. (Calgary time) on a Business Day, shall be deemed to be received on the next following Business Day. Anything mailed shall not be deemed to have been given until it is actually received. The Guarantor or the Corporation may from time to time notify the Trustee of a change in address or facsimile number which thereafter, until changed by like notice, shall be the address or facsimile number of the Guarantor or the Corporation for all purposes of this Guarantee.

1.6   Notice to Holders; Waiver

        Where this Guarantee provides for notice of any event to the Holders of Series 1 Shares by the Guarantor or the Trustee, such notice shall be sufficiently given (unless otherwise herein expressly provided) if in writing and mailed, first-class postage prepaid, to each such Holder affected by such

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event, at his address as it appears in the list of Holders as provided by the Corporation, not later than the latest date, and not earlier than the earliest date, prescribed for the giving of such notice or in any other manner from time to time permitted by applicable laws, including, without limitation, internet-based or other electronic communications. In any case where notice to the Holders of Series 1 Shares is given by mail, neither the failure to mail such notice, nor any defect in any notice so mailed, to any particular Holder shall affect the sufficiency of such notice with respect to other Holders of Series 1 Shares. Any notice mailed to a Holder in the manner herein prescribed shall be conclusively deemed to have been received by such Holder, whether or not such Holder actually receives such notice.

        Any request, demand, authorization, direction, notice, consent or waiver required or permitted under this Guarantee shall be in the English language.

        Where this Guarantee provides for notice in any manner, such notice may be waived in writing by the Person entitled to receive such notice, either before or after the event, and such waiver shall be the equivalent of such notice. Waivers of notice by Holders shall be filed with the Trustee, but such filing shall not be a condition precedent to the validity of any action taken in reliance upon such waiver.

1.7   Effect of Headings and Table of Contents

        The Article and Section headings herein and the Table of Contents are for convenience only and shall not affect the construction hereof.

1.8   Successors and Assigns

        All covenants and agreements in this Guarantee by the Guarantor shall bind its successors and assigns, whether so expressed or not.

1.9   Separability Clause

        In case any provision in this Guarantee shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

1.10 Governing Law

        This Guarantee shall be governed by and construed in accordance with the laws of the Province of Alberta and the federal laws of Canada applicable therein.

1.11 No Recourse Against Others

        A director, officer, employee or shareholder, as such, of the Guarantor shall not have any liability for any obligations of the Guarantor under this Guarantee or for any claim based on, in respect of or by reason of such obligations or its creation.

1.12 Multiple Originals

        The parties may sign any number of copies of this Guarantee. Each signed copy shall be an original, but all of them together represent the same agreement. One signed copy is enough to prove this Guarantee.

1.13 Language

        Les parties aux présentes ont exigé que Ia présente convention ainsi que tous les documents et avis qui s'y rattachent et/ou qui en découleront soient rediges et exécutés en langue anglaise. The parties hereto have required that this Guarantee and all documents and notices related thereto be drafted and executed in English.

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ARTICLE 2
GUARANTEE

2.1   Guarantee

        The Guarantor irrevocably and unconditionally guarantees in favour of the Holders the due and punctual payment of the Preferred Share Obligations (without duplication of amounts theretofore paid by or on behalf of the Corporation), regardless of any defense (except for the defense of payment by the Corporation), right of setoff or counterclaim which the Guarantor may have or assert. The Guarantor's obligation to pay a Preferred Share Obligation may be satisfied by (i) direct payment to the Holders or (ii) payment to the Holders through the facilities of the Trustee. The Guarantor shall give prompt written notice to the Trustee in the event it makes a direct payment to the Holders hereunder.

2.2   Waiver of Notice

        The Guarantor hereby waives notice of acceptance of this Guarantee.

2.3   Guarantee Absolute

        The Guarantor guarantees that the Preferred Share Obligations will be paid strictly in accordance with the terms of the Series 1 Shares and this Guarantee within the time required by Section 2.1 regardless of any law, regulation or order now or hereafter in effect in any jurisdiction affecting any such terms or the rights of the Holders with respect thereto. The liability of the Guarantor under this Guarantee shall be absolute and unconditional irrespective of:

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it being the intent of the Guarantor that its obligations in respect of Preferred Share Obligations shall be absolute and unconditional under all circumstances and shall not be discharged except by payment in full of the Preferred Share Obligations or as otherwise set out herein. The Holders shall not be bound or obliged to exhaust their recourse against the Corporation or any other persons or to take any other action before being entitled to demand payment from the Guarantor hereunder.

        There shall be no obligation of the Holders to give notice to, or obtain the consent of, the Guarantor with respect to the happening of any of the foregoing.

2.4   Continuing Guarantee

        This Guarantee shall apply to and secure any ultimate balance due or remaining due to the Holders in respect of the Preferred Share Obligations and shall be binding as an absolute and continuing obligation of the Guarantor. This Guarantee shall continue to be effective or be reinstated, as the case may be, if at any time payment of any of the Preferred Share Obligations must be rescinded, is declared voidable, or must otherwise be returned by the Holders for any reason, including the insolvency, bankruptcy, dissolution or reorganization of the Corporation or upon or as a result of the appointment of a custodian, receiver, trustee or other officer with similar powers with respect to the Corporation or any substantial part of its property, all as though such payment had not been made. If at any time the Corporation is precluded from making payment when due in respect of any Preferred Share Obligations by reason of the provisions of the ABCA or otherwise, such amounts shall nonetheless be deemed to be due and payable by the Corporation to the Holders for all purposes of this Guarantee and the Preferred Share Obligations shall be immediately due and payable to the Holders. This is a guarantee of payment, and not merely a deficiency or collection guarantee.

2.5   Rights of Holders

        The Guarantor expressly acknowledges that: (i) this Guarantee will be deposited with the Trustee to be held for the benefit of the Holders; and (ii) the Trustee has the right to enforce this Guarantee on behalf of the Holders.

2.6   Guarantee of Payment

        If the Corporation shall fail to pay any of the Preferred Share Obligations when due, the Guarantor shall pay to the Holders the Preferred Share Obligations immediately after demand made in writing by one or more Holders or the Trustee, but in any event within 15 days of any failure by the Corporation to pay the Preferred Share Obligations when due, without any evidence that the Holders have demanded that the Corporation pay any of the Preferred Share Obligations or that the Corporation has failed to do so. Notwithstanding anything to the contrary herein, the Holders or the

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Trustee shall first seek payment of the Preferred Share Obligations under the Guarantee Indenture dated as of May 25, 2007 among Capital Power Income L.P., the Corporation and the Trustee.

2.7   Subrogation

        The Guarantor shall have no right of subrogation in respect of any payment made to the Holders hereunder until such time as the Preferred Share Obligations have been fully satisfied. In the case of the liquidation, dissolution, winding-up or bankruptcy of the Corporation (whether voluntary or involuntary), or if the Corporation makes an arrangement or compromise or proposal with its creditors, the Holders shall have the right to rank for their full claim and to receive all dividends or other payments in respect thereof until their claims have been paid in full, and the Guarantor shall continue to be liable to the Holders for any balance which may be owing to the Holders by the Corporation. The Preferred Share Obligations shall not, however, be released, discharged, limited or affected by the failure or omission of the Holders to prove the whole or part of any claim against the Corporation. If any amount is paid to the Guarantor on account of any subrogation arising hereunder at any time when the Preferred Share Obligations have not been fully satisfied, such amount shall be held in trust for the benefit of the Holders and shall forthwith be paid to the Holders to be credited and applied against the Preferred Share Obligations.

2.8   Independent Obligations

        The Guarantor acknowledges that its obligations hereunder are independent of the obligations of the Corporation with respect to the Series 1 Shares and that the Guarantor shall be liable as principal and as debtor hereunder to make Preferred Share Obligations pursuant to the terms of this Guarantee notwithstanding the occurrence of any event referred to in subsections (a) through (l), inclusive, of Section 2.3, if the Holders should make a demand upon the Guarantor. The Guarantor will pay the Preferred Share Obligations without regard to any equities between it and the Corporation or any defence or right of set-off, compensation, abatement, combination of accounts or cross-claim that it or the Corporation may have.

2.9   Guarantor to Investigate Financial Condition of the Corporation

        The Guarantor acknowledges that it has fully informed itself about the financial condition of the Corporation. The Guarantor assumes full responsibility for keeping fully informed of the financial condition of the Corporation and all other circumstances affecting the Corporation's ability to pay the Preferred Share Obligations.


ARTICLE 3
SUBORDINATION OF OBLIGATIONS TO SENIOR INDEBTEDNESS

3.1   Applicability of Article

        The obligations of the Guarantor hereunder shall be subordinate and subject in right of payment, to the extent and in the manner hereinafter set forth in the following sections of this Article 3, to the prior payment in full, of all Senior Indebtedness of the Guarantor and the Trustee and each Holder of Series 1 Shares as a condition to and by acceptance of the benefits conferred hereby agrees to and shall be bound by the provisions of this Article 3.

3.2   Order of Payment

        Upon any distribution of the assets of the Guarantor on any dissolution, winding up, liquidation or reorganization of the Guarantor (whether in bankruptcy, insolvency or receivership proceedings, or

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upon an "assignment for the benefit of creditors" or any other marshalling of the assets and liabilities of the Guarantor, or otherwise):

3.3   Subrogation to Rights of Holders of Senior Indebtedness

        Subject to the payment in full of all Senior Indebtedness, the Holders of the Series 1 Shares shall be subrogated to the rights of the holders of Senior Indebtedness to receive payments or distributions of assets of the Guarantor (to the extent of the application thereto of such payments or other assets which would have been received by the Holders of the Series 1 Shares but for the provisions hereof) until the Preferred Share Obligations shall be paid in full, and no such payments or distributions to the Holders of the Series 1 Shares of cash, property or securities, which otherwise would be payable or distributable to the holders of the Senior Indebtedness, shall, as between the Guarantor, its creditors (other than the holders of Senior Indebtedness), and the Holders of Series 1 Shares, be deemed to be a payment by the Guarantor to the holders of the Senior Indebtedness or on account of the Senior Indebtedness, it being understood that the provisions of this Article 3 are and are intended solely for the purpose of defining the relative rights of the Holders of the Series 1 Shares, on the one hand, and the holders of Senior Indebtedness, on the other hand.

3.4   Obligation to Pay Not Impaired

        Nothing contained in this Article 3 or elsewhere in this Guarantee or in the Series 1 Shares is intended to or shall impair, as between the Guarantor, its creditors (other than the holders of Senior Indebtedness), and the Holders of the Series 1 Shares, the obligation of the Guarantor, which is absolute and unconditional, to pay to the Holders of the Series 1 Shares the Preferred Share Obligations in accordance herewith, as and when the same shall become due and payable in accordance with this Guarantee, or affect the relative rights of the Holders of the Series 1 Shares and creditors of the Guarantor other than the holders of the Senior Indebtedness, nor shall anything herein or therein prevent the Trustee or the Holder of any Series 1 Share from exercising all remedies otherwise permitted by applicable law upon default under this Guarantee, subject to the rights, if any, under this Article 3 of the holders of Senior Indebtedness in respect of cash, property or securities of the Guarantor received upon the exercise of any such remedy.

3.5   No Payment if Senior Indebtedness In Default

        Upon the maturity of any Senior Indebtedness by lapse of time, acceleration or otherwise, then, except as provided in Section 3.6, all principal of and interest on all such matured Senior Indebtedness shall first be paid in full, or shall first have been duly provided for, before any payment is made on account of the Preferred Share Obligations.

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have ceased to exist, no payment (by purchase of the Series 1 Shares or otherwise) shall be made by the Guarantor with respect to the Preferred Share Obligations and neither the Trustee nor the Holders of Series 1 Shares shall be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including without limitation by set-off, combination of accounts or otherwise in any manner whatsoever) on account of the Preferred Share Obligations after the happening of such a default (except as provided in Section 3.8), and unless and until such default shall have been cured or waived or shall have ceased to exist, such payments shall be held in trust for the benefit of, and, if and when such Senior Indebtedness shall have become due and payable, shall be paid over to, the holders of the Senior Indebtedness or their representative or representatives or to the trustee or trustees under any indenture under which any instruments evidencing an amount of the Senior Indebtedness remaining unpaid until all such Senior Indebtedness shall have been paid in full, after giving effect to any concurrent payment of distribution to the holders of such Senior Indebtedness.

        The fact that any payment hereunder is prohibited by this Section 3.5 shall not prevent the failure to make such payment from being an Event of Default hereunder.

3.6   Payment on Series 1 Shares Permitted

        Nothing contained in this Article 3 or elsewhere in this Guarantee, or in any of the Series 1 Shares, shall affect the obligation of the Guarantor to make, or prevent the Guarantor from making, at any time except during the pendency of any dissolution, winding up or liquidation of the Guarantor or reorganization proceedings specified in Section 3.2 affecting the affairs of the Guarantor, any payment on account of the Preferred Share Obligations, except that the Guarantor shall not make any such payment other than as contemplated by this Article 3, if it is in default in payment of any Senior Indebtedness. The fact that any such payment is prohibited by this Section 3.6 shall not prevent the failure to make such payment from being an Event of Default hereunder. Nothing contained in this Article 3 or elsewhere in this Guarantee, or in any of the Series 1 Shares, shall prevent the application by the Trustee of any moneys deposited with the Trustee hereunder for the purpose so deposited, to the payment of or on account of the Preferred Share Obligations unless and until the Trustee shall have received written notice from the Guarantor or from the holder of Senior Indebtedness or from the representative of any such holder of default with respect to any Senior Indebtedness permitting the holders thereof to accelerate the maturity thereof.

3.7   Confirmation of Subordination

        As a condition to the benefits conferred hereby on each Holder of Series 1 Shares, each such Holder by his acceptance thereof authorizes and directs the Trustee on the Holder's behalf to take such action as may be necessary or appropriate to effectuate the subordination as provided in this Article 3 and appoints the Trustee as the Holder's attorney-in-fact for any and all such purposes. Upon request of the Guarantor, and upon being furnished an Officers' Certificate stating that one or more named persons are holders of Senior Indebtedness, or the representative or representatives of such holders, or the trustee or trustees under which any instrument evidencing such Senior Indebtedness may have been issued, and specifying the amount and nature of such Senior Indebtedness, the Trustee shall enter into a written agreement or agreements with the Guarantor and the person or persons named in such Officers' Certificate providing that such person or persons are entitled to all the rights and benefits of this Article 3 as the holder or holders, representative or representatives, or trustee or trustees of the Senior Indebtedness specified in such Officers' Certificate and in such agreement. Such agreement shall be conclusive evidence that the indebtedness specified therein is Senior Indebtedness, however, nothing herein shall impair the rights of any holder of Senior Indebtedness who has not entered into such an agreement.

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3.8   Trustee May Hold Senior Indebtedness

        The Trustee is entitled to all the rights set forth in this Article 3 with respect to any Senior Indebtedness at the time held by it, to the same extent as any other holder of Senior Indebtedness, and nothing in this Guarantee deprives the Trustee of any of its rights as such holder.

3.9   Rights of Holders of Senior Indebtedness Not Impaired

        No right of any present or future holder of any Senior Indebtedness to enforce the subordination herein will at any time or in any way be prejudiced or impaired by any act or failure to act on the part of the Guarantor or by any non-compliance by the Guarantor with the terms, provisions and covenants of this Guarantee, regardless of any knowledge thereof which any such holder may have or be otherwise charged with.

3.10 Altering the Senior Indebtedness

        The holders of the Senior Indebtedness have the right to extend, renew, modify or amend the terms of the Senior Indebtedness or any security therefor and to release, sell or exchange such security and otherwise to deal freely with the Guarantor, all without notice to or consent of the Holders of the Series 1 Shares or the Trustee and without affecting the liabilities and obligations of the parties to this Guarantee or the Holders of the Series 1 Shares or the Trustee.

3.11 Additional Indebtedness

        This Guarantee does not restrict the Guarantor from incurring any indebtedness for borrowed money or otherwise or mortgaging, pledging or charging its properties to secure any indebtedness.


ARTICLE 4
TERMINATION AND REMEDIES

4.1   Termination of Guarantee

        This Guarantee shall terminate upon the occurrence of the following events:

        Upon termination of this Guarantee the Trustee shall, upon request of the Guarantor, provide to the Guarantor written documentation acknowledging the termination of this Guarantee.

        Notwithstanding the termination of this Guarantee, the obligations of the Guarantor to the Trustee under Section 5.3 shall survive.

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4.2   Suits for Enforcement by the Trustee

        In the event that the Guarantor fails to pay the Preferred Share Obligations as required (an "Event of Default") pursuant to the terms of this Guarantee, the Holders may institute judicial proceedings for the collection of the moneys so due and unpaid, may prosecute such proceeding to judgment or final decree and may enforce the same against the Corporation and/or the Guarantor and may collect the moneys adjudged or decreed to be payable in the manner provided by law out of the property of the Guarantor.

        If an Event of Default occurs and is continuing, the Trustee may in its discretion proceed to protect and enforce its rights, and the rights of the Holders, upon being indemnified and funded to its satisfaction by the Holders, by such appropriate judicial proceedings as the Trustee shall deem most effectual to protect and enforce any such rights, whether for the specific enforcement of any covenant or agreement in this Guarantee or in aid of the exercise of any power granted herein, or to enforce any other proper remedy.

4.3   Trustee May File Proofs of Claim

        In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Guarantor or the property of the Guarantor, the Trustee shall be entitled and empowered, by intervention in such proceeding or otherwise,

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Holder to make such payments to the Trustee and, in the event that the Trustee shall consent to the making of such payments directly to the Holders, to pay to the Trustee all amounts due to it hereunder including, without limitation, the reasonable compensation, expenses, disbursements and advances of the Trustee in or about the execution of its trust, or otherwise in relation hereto, with interest thereon as herein provided.

        Nothing herein contained shall be deemed to authorize the Trustee to authorize or consent to or accept or adopt on behalf of any Holder any plan of reorganization, arrangement, adjustment or composition affecting the Series 1 Shares or the rights of any Holder thereof or to authorize the Trustee to vote in respect of the claim of any Holder in any such proceeding.

4.4   Trustee May Enforce Claims Without Possession of Series 1 Shares

        All rights of action and claims under this Guarantee may be prosecuted and enforced by the Trustee without the possession of any of the Series 1 Shares in any proceeding relating thereto, and any such proceeding instituted by the Trustee shall be brought in its own name as trustee of an express trust, and any recovery of judgment shall, after provision for the payment of the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, be for the rateable benefit of the Holders of the Series 1 Shares in respect of which such judgment has been recovered.

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4.5   Application of Money Collected

        Any money collected by the Trustee pursuant to this Article shall be applied in the following order:

4.6   Limitation on Suits

        No Holder of any outstanding Series 1 Shares shall have any right to institute any proceeding, judicial or otherwise, with respect to this Guarantee, or for the appointment of a receiver or trustee, or for any other remedy hereunder, unless:

it being understood and intended that no one or more of such Holders shall have any right in any manner whatever by virtue of, or by availing of, any provision of this Guarantee to affect, disturb or prejudice the rights of any other Holders of the outstanding Series 1 Shares, or to obtain or to seek to obtain priority or preference over any other of such Holders or to enforce any right under this Guarantee, except in the manner herein provided and for the equal and rateable benefit of all Holders of the outstanding Series 1 Shares.

4.7   Restoration of Rights and Remedies

        If the Trustee or any Holder has instituted any proceeding to enforce any right or remedy under this Guarantee and such proceeding has been discontinued or abandoned for any reason, or has been determined adversely to the Trustee or to such Holder, then and in every such case, subject to any determination in such proceeding, the Guarantor, the Trustee and the Holders of Series 1 Shares shall be restored severally and respectively to their former positions hereunder and thereafter all rights and remedies of the Trustee and the Holders shall continue as though no such proceeding had been instituted.

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4.8   Rights and Remedies Cumulative

        No right or remedy herein conferred upon or reserved to the Trustee or to the Holders of Series 1 Shares is intended to be exclusive of any other right or remedy, and every right and remedy shall, to the extent permitted by law, be cumulative and in addition to every other right and remedy given hereunder or now or hereafter existing at law or in equity or otherwise. The assertion or employment of any right or remedy hereunder, or otherwise, shall not prevent the concurrent assertion or employment of any other appropriate right or remedy.

4.9   Delay or Omission Not Waiver

        No delay or omission of the Trustee or of any Holder of any Series 1 Shares to exercise any right or remedy accruing upon an Event of Default shall impair any such right or remedy or constitute a waiver of any such Event of Default or an acquiescence therein. Every right and remedy given by this Article or by law to the Trustee or to the Holders may be exercised from time to time, and as often as may be deemed expedient, by the Trustee or by the Holders, as the case may be.

4.10 Control by Holders

        The Holders representing not less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 1 Shares affected by an Event of Default (determined as one class) shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee, with respect to this Guarantee, provided that in each case:

4.11 Waiver of Stay or Extension Laws

        The Guarantor covenants (to the extent that it may lawfully do so) that it will not at any time insist upon or plead, or in any manner whatsoever claim or take the benefit or advantage of, any stay or extension law wherever enacted, now or at any time hereafter in force, which may affect the covenants or the performance of this Guarantee, and the Guarantor (to the extent that it may lawfully do so) hereby expressly waives all benefit or advantage of any such law and covenants that it will not hinder, delay or impede the execution of any power herein granted to the Trustee, but will suffer and permit the execution of every such power as though no such law had been enacted.

4.12 Undertaking for Costs

        All parties to this Guarantee agree, and each Holder of any Series 1 Shares by acceptance thereof and by acceptance of the benefits hereof shall be deemed to have agreed, that any court may in its discretion require, in any suit for the enforcement of any right or remedy under this Guarantee, or in any suit against the Trustee for any action taken, suffered or omitted by it as Trustee, the filing by any party litigant in such suit of an undertaking to pay the costs of such suit and that such court may in its discretion assess reasonable costs, including reasonable lawyers' fees, against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant; but the provisions of this Section shall not apply to (i) any suit instituted by the Guarantor, (ii) any suit instituted by the Trustee, (iii) any suit instituted by any Holder, or group of Holders, holding in the aggregate more than 25% of the aggregate Liquidation Amount of all of the then

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outstanding Series 1 Shares, or (iv) any suit instituted by any Holder for the enforcement of the payment of the Preferred Share Obligations.


ARTICLE 5
THE TRUSTEE

5.1   Certain Duties and Responsibilities

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5.2   Certain Rights of Trustee

        Subject to the provisions of Section 5.1:

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5.3   Protection of Trustee

        By way of supplement to the provisions of any law for the time being relating to trustees, it is expressly declared and agreed as follows:

5.4   Trustee Not Required to Give Security

        The Trustee shall not be required to give security for the execution of the trusts or its conduct or administration hereunder.

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5.5   No Person Dealing with Trustee Need Enquire

        No person dealing with the Trustee shall be concerned to enquire whether the powers that the Trustee is purporting to exercise have become exercisable, or whether any money remains due upon the Series 1 Shares or to see to the application of any money paid to the Trustee.

5.6   May Hold Series 1 Shares

        Subject to applicable law, the Trustee or any other agent of the Guarantor, in its individual or in any other capacity, may become the owner or pledgee of the Series 1 Shares and, subject to Section 5.8, may otherwise deal with the Guarantor with the same rights it would have if it were not the Trustee, and without being liable to account for any profit made thereby.

5.7   Moneys Held in Trust

        Any money held by the Trustee, which under the trusts of this Guarantee may be invested, shall be invested and reinvested by the Trustee, in accordance with Schedule A hereto. Pending such investment, such money shall be placed by the Trustee on deposit at interest at the then current rate in a Canadian chartered bank or trust company.

5.8   Conflict of Interest

5.9   Corporate Trustee Required; Eligibility

        There shall at all times be a Trustee hereunder which shall be a corporation resident or authorized to carry on the business of a trust company in the Province of Alberta. Neither the Guarantor nor any affiliate of the Guarantor shall serve as Trustee. If at any time the Trustee shall cease to be eligible in accordance with the provisions of this Section, the Trustee shall resign immediately in the manner and with the effect hereinafter specified in this Article.

5.10 Resignation and Removal; Appointment of Successor

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5.11 Acceptance of Appointment by Successor

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5.12 Merger, Consolidation, Amalgamation or Succession to Business

        Any corporation into which the Trustee may be merged or with which it may be consolidated or amalgamated, or any corporation resulting from any merger, consolidation or amalgamation to which the Trustee shall be a party, or any corporation succeeding to all or substantially all of the corporate trust business of the Trustee, shall be the successor of the Trustee hereunder, provided such corporation shall be otherwise qualified and eligible under this Article, without the execution or filing of any paper or instrument or any further act on the part of any of the parties hereto.

5.13 Not Bound to Act

        The Trustee shall retain the right not to act and shall not be liable for refusing to act if, due to a lack of information or for any other reason whatsoever, the Trustee, in its sole judgment, determines that such act might cause it to be in non-compliance with any applicable anti-money laundering or anti-terrorist legislation, regulation or guideline. Further, should the Trustee, in its sole judgment, determine at any time that its acting under this Guarantee has resulted in its being in non-compliance with any applicable anti-money laundering, or anti-terrorist legislation, regulation or guideline, then it shall have the right to resign on 10 days written notice to the Guarantor, provided that (i) the Trustee's

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written notice shall describe the circumstances of such non-compliance; and (ii) if such circumstances are rectified to the Trustee's satisfaction, acting reasonably, within such 10 day period, then such resignation shall not be effective.

5.14 Trustee's Privacy Clause

        The parties acknowledge that federal and/or provincial legislation that addresses the protection of individuals' personal information (collectively, "Privacy Laws") applies to obligations and activities under this Guarantee. Despite any other provision of this Guarantee, no party shall take or direct any action that would contravene, or cause the other to contravene, applicable Privacy Laws. The Guarantor shall, prior to transferring or causing to be transferred personal information to the Trustee, obtain and retain required consents of the relevant individuals to the collection, use and disclosure of their personal information, or shall have determined that such consents either have previously been given upon which the parties can rely or are not required under the Privacy Laws. The Trustee shall use commercially reasonable efforts to ensure that its services hereunder comply with Privacy Laws. Specifically, the Trustee agrees: (i) to have a designated a chief privacy officer; (ii) to maintain policies and procedures to protect personal information and to receive and respond to any privacy complaint or inquiry; (iii) to use personal information solely for the purposes of providing its services under or ancillary to this Guarantee and not to use it for any other purpose except with the consent of or direction from the Guarantor or the individual involved; (iv) not to sell or otherwise improperly disclose personal information to any third party; and (v) to employ administrative, physical and technological safeguards to reasonably secure and protect personal information against loss, theft, or unauthorized access, use or modification.

5.15 Compensation and Reimbursement

        The Guarantor agrees:

        The Trustee's remuneration, shall be payable out of any funds coming into the possession of the Trustee in priority to any payment of the Preferred Share Obligations. The said remuneration shall continue to be payable whether or not this Guarantee shall be in the course of administration by or under the direction of a court of competent jurisdiction. Any amount due under this Section and unpaid within 30 days after demand for such payment by the Trustee, shall bear interest at the then current rate of interest charged by the Trustee to its corporate customers. This Section 5.15 shall survive the removal or termination of the Trustee and the termination of this Guarantee.

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ARTICLE 6
HOLDERS' LISTS AND REPORTS BY TRUSTEE AND GUARANTOR

6.1   List of Holders

        The Corporation shall furnish or cause to be furnished to the Trustee at such times as the Trustee may request in writing, within five Business Days after the receipt by the Corporation of any such request, a list, in such form as the Trustee may reasonably require, of the names and addresses of the Holders as of a date not more than 15 days prior to the time such list is furnished, in each case to the extent such information is in the possession or control of the Corporation and is not identical to a previously supplied list of Holders or has not otherwise been received by the Trustee in its capacity as such. The Trustee may destroy any list of Holders previously given to it on receipt of a new list of Holders.

        The Corporation shall provide the Trustee with an updated list of Holders within 15 days of the Guarantor or any affiliate of the Guarantor becoming a Holder.

6.2   Access to list of Holders

        A Holder may, upon payment to the Trustee of a reasonable fee, require the Trustee to furnish within 10 days after receiving the affidavit or statutory declaration referred to below, a list setting out (i) the name and address of every Holder of Series 1 Shares, (ii) the aggregate number of Series 1 Shares owned by each such Holder, and (iii) the aggregate number of the Series 1 Shares then outstanding, each as shown on the records of the Trustee on the day that the affidavit or statutory declaration is delivered to the Trustee. The affidavit or statutory declaration, as the case may be, shall contain (i) the name and address of the Holder, (ii) where the applicant is a corporation, its name and address for service, (iii) a statement that the list will not be used except in connection with an effort to influence the voting of the Holders of Series 1 Shares, or any other matter relating to the Guarantee, and (iv) such other undertaking as may be required by applicable law. Where the Holder is a corporation, the affidavit or statutory declaration shall be made by a director or officer of the corporation.

6.3   Communications to Holders

        The rights of Holders to communicate with other Holders with respect to their rights under this Guarantee and the corresponding rights and privileges of the Trustee, shall be governed by applicable law.

        Every Holder of Series 1 Shares, by receiving and holding the same, agrees with the Guarantor and the Trustee that neither the Guarantor nor the Trustee nor any agent of either of them shall be held accountable by reason of any disclosure of information as to the names and addresses of Holders made pursuant to the terms hereof or applicable law.


ARTICLE 7
CONVEYANCE, TRANSFER OR LEASE

7.1   Conveyance, Transfer or Lease; Only on Certain Terms

        The Guarantor shall not convey, transfer or lease all or substantially all of its properties and assets to any Person, unless:

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        This Section shall only apply to conveyances, leases and transfers by the Guarantor as transferor or lessor.

7.2   Successor Person Substituted

        Upon any conveyance, transfer or lease of all or substantially all of the properties and assets of the Guarantor to any Person in accordance with Section 7.1, the successor Person to which such conveyance, transfer or lease is made shall succeed to, and be substituted for, and may exercise every right and power of, the Guarantor under this Guarantee with the same effect as if such successor Person had been named as the Guarantor herein, and in the event of any such conveyance or transfer, the Guarantor (which term shall for this purpose means the Person named as the "Guarantor" in the first paragraph of this Guarantee or any successor Person which shall theretofore become such in the manner described in Section 7.1), except in the case of a lease, shall be discharged of all obligations and covenants under this Guarantee.

7.3   Sale of Common Shares of the Corporation and/or Limited Partnership Units of Capital Power Income L.P.

        The Guarantor shall not, directly or indirectly, convey, transfer or otherwise dispose of any limited partnership units of Capital Power Income L.P., common shares of CPI Investments Inc., common shares of CPI Income Services Ltd. or common shares of the Corporation beneficially owned by it, if any such conveyance, transfer or disposition would cause the Guarantor to cease to be an affiliate of Capital Power Income L.P. or the Corporation, unless all of the beneficial holders of limited partnership units of Capital Power Income L.P., common shares of CPI Investments Inc., common shares of CPI Income Services Ltd. and common shares of the Corporation (other than the Guarantor) shall have entered into a guarantee indenture with the Trustee, substantially similar to this guarantee indenture and in form and substance satisfactory to the Trustee, acting reasonably, whereby such holders irrevocably and unconditionally guarantee in favour of the Holders the due and punctual payment of the Preferred Share Obligations on the same terms and conditions as set forth herein.


ARTICLE 8
SUPPLEMENTAL INDENTURES

8.1   Supplemental Indentures Without Consent of Holders

        Without the consent of any Holders, the Guarantor, when authorized by or pursuant to a Board Resolution, and the Trustee, at any time and from time to time may enter into one or more indentures supplemental hereto, in form satisfactory to the Trustee, for any of the following purposes:

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8.2   Supplemental Guarantees with Consent of Holders

        With the consent of either (i) the Holders representing not less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 1 Shares, by Act of such Holders delivered to the Guarantor and the Trustee, or (ii) if a meeting of the Holders is called for obtaining such consent, Holders representing not less than a majority of the aggregate Liquidation Amount of all Series 1 Shares represented at such meeting and voting in respect of such consent, the Guarantor, when authorized by or pursuant to a Board Resolution, and the Trustee may enter into an indenture or indentures supplemental hereto for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of this Guarantee or of modifying in any manner the rights of the Holders under this Guarantee; provided, however, that no such supplemental indenture shall, without the consent of the Holders representing not less than 662/3% of the aggregate Liquidation Amount of all of the then outstanding Series 1 Shares or, if a meeting of the Holders is called for obtaining such consent, Holders representing not less than a majority of the aggregate Liquidation Amount of all Series 1 Shares represented at such meeting and voting in respect of such consent, as the case may be,

8.3   Execution of Supplemental Guarantees

        In executing, or accepting the additional trusts created by, any supplemental indenture permitted by this Article or the modifications thereby of the trusts created by this Guarantee, the Trustee shall be entitled to receive, and shall be fully protected in acting and relying upon, an Opinion of Counsel stating that the execution of such supplemental indenture is authorized or permitted by this Guarantee. The Trustee may, but shall not be obligated to, enter into any such supplemental indenture which affects the Trustee's own rights, duties or immunities under this Guarantee or otherwise.

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8.4   Effect of Supplemental Indentures

        Upon the execution of any supplemental indenture under this Article, this Guarantee shall be modified in accordance therewith, and such supplemental indenture shall form a part of this Guarantee for all purposes.

8.5   Notice of Supplemental Guarantees

        Promptly after the execution by the Guarantor and the Trustee of any supplemental indenture pursuant to the provisions of Section 8.2, the Guarantor shall give notice thereof to the Holders of each of the outstanding Series 1 Shares affected, in the manner provided for in Section 1.6, setting forth in general terms the substance of such supplemental indenture.


ARTICLE 9
COVENANTS

9.1   Existence

        Subject to Article 7 the Guarantor will do or cause to be done all things necessary to preserve and keep in full force and effect its existence and the rights and franchises of the Guarantor and its subsidiaries; provided, however, that the Guarantor shall not be required to preserve any such right or franchise if the Guarantor shall determine that the preservation thereof is no longer desirable in the conduct of the business of the Guarantor.

9.2   Trustee Not Required to Verify Liquidation Amount

        The Guarantor will not require the Trustee to calculate or verify the Liquidation Amount.

9.3   Restriction on Dividends

        The Guarantor hereby covenants and agrees that if and for so long as either the board of directors of the Corporation has failed to declare, or the Corporation has failed to pay, dividends on the Series 1 Shares, in each case, in accordance with the share conditions attaching thereto, then the Guarantor shall not declare or pay any dividends on its shares or make any distributions or pay any dividends on securities of any successor entity of the Guarantor.


ARTICLE 10
PURCHASE OF SERIES 1 SHARES

10.1 Purchase of Series 1 Shares

        Subject to applicable law, at any time when the Guarantor is not in default hereunder, it may purchase Series l Shares at any price in the market (including purchases from or through an investment dealer or a firm holding membership on a recognized stock exchange) or by tender available to all Holders of Series 1 Shares or by private contract.

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ARTICLE 11
MEETINGS OF HOLDERS OF SERIES 1 SHARES

11.1 Purposes for Which Meetings May Be Called

        A meeting of the Holders of the Series 1 Shares may be called at any time and from time to time pursuant to the provisions of this Article for one or more of the following purposes:

11.2 Call, Notice and Place of Meetings

11.3 Persons Entitled to Vote at Meetings

        To be entitled to vote at any meeting of Holders of Series 1 Shares, a Person shall be (1) a Holder of one or more outstanding Series 1 Shares, or (2) a Person appointed by an instrument in writing as proxy for a Holder or Holders of one or more outstanding Series 1 Shares by such Holder of Holders. The only Persons who shall be entitled to be present or to speak at any meeting of Holders of Series 1 Shares shall be the Person entitled to vote at such meeting and their counsel, any representatives of the Trustee and its counsel, and any representatives of the Guarantor and its counsel.

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11.4 Quorum; Action

        The Holders representing not less than 25% of the aggregate Liquidation Amount of all of the then outstanding Series 1 Shares shall constitute a quorum for a meeting of Holders of Series 1 Shares; provided, however, that, if any action is to be taken at such meeting with respect to a consent or waiver which this Guarantee expressly provides may be given by the Holders of not less than a specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series 1 Shares, the Persons entitled to vote such specified percentage in aggregate amount of the outstanding Series 1 Shares shall constitute a quorum. In the absence of a quorum within 30 minutes of the time appointed for any such meeting, the meeting shall, if convened at the request of Holders of Series 1 Shares, be dissolved. In any other case the meeting may be adjourned for a period of not less than 10 days as determined by the chairman of the meeting prior to the adjournment of such meeting. In the absence of a quorum at any such adjourned meeting, such adjourned meeting may be further adjourned for a period of not less than 10 days as determined by the chairman of the meeting prior to the adjournment of such adjourned meeting. Notice of the reconvening of any adjourned meeting shall be given as provided in Section 11.2(a), except that such notice need be given only once not less than five days prior to the date on which the meeting is scheduled to be reconvened.

        Subject to the foregoing, at the reconvening of any meeting adjourned for lack of a quorum, the Holders of Series 1 Shares entitled to vote at such meeting present in person or by proxy shall constitute a quorum for the taking of any action set forth in the notice of the original meeting.

        Except as limited by the proviso to Section 8.2, any resolution presented to a meeting or adjourned meeting duly reconvened at which a quorum is present as aforesaid may be adopted by the affirmative vote of the Holders representing not less than a majority of the aggregate Liquidation Amount of Series 1 Shares represented at such meeting in person or by proxy; provided, however, that, except as limited by the proviso to Section 8.2, any resolution with respect to any request, demand, authorization, direction, notice, consent, waiver or other action which this Guarantee expressly provides may be made, given or taken by the Holders of a specified percentage, which is less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 1 Shares may be adopted at a meeting or an adjourned meeting duly reconvened and at which a quorum is present as aforesaid by the affirmative vote of the Holders of not less than such specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series l Shares.

        Any resolution passed or decision taken at any meeting of Holders of Series 1 Shares duly held in accordance with this Section shall be binding on all the Holders of Series 1 Shares, whether or not present or represented at the meeting.

        Notwithstanding the foregoing provisions of this Section 11.4, if any action is to be taken at a meeting of Holders of Series 1 Shares with respect to any request, demand, authorization, direction, notice, consent, waiver or other action that this Guarantee expressly provides may be made, given or taken by the Holders of a specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series 1 Shares affected thereby:

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11.5 Determination of Voting Rights; Conduct and Adjournment of Meetings

11.6 Counting Votes and Recording Action of Meetings

        The vote upon any resolution submitted to any meeting of Holders of Series 1 Shares shall be by written ballots on which shall be subscribed the signatures of the Holders of Series 1 Shares or of their representatives by proxy and the number of outstanding Series 1 Shares held or represented by them. The permanent chairman of the meeting shall appoint two inspectors of votes who shall count all votes cast at the meeting for or against any resolution and who shall make and file with the secretary of the meeting their verified written reports in duplicate of all votes cast at the meeting. A record, at least in duplicate, of the proceedings of each meeting of Holders of Series 1 Shares shall be prepared by the Secretary of the meeting and there shall be attached to said record the original reports of the inspectors of votes on any vote by ballot taken thereat and affidavits by one or more persons having knowledge of the facts setting forth a copy of the notice of the meeting and showing that said notice was given as provided in Section 11.2 and, if applicable, Section 11.4. Each copy shall be signed and verified by the affidavits of the permanent chairman and secretary of the meeting and one such copy shall be delivered to the Guarantor, and another to the Trustee to be preserved by the Trustee, the latter to have attached thereto the ballots voted at the meeting. Any record so signed and verified shall be conclusive evidence of the matters therein stated.

        This Guarantee may be executed in any number of counterparts, each of which so executed shall be deemed to be an original, but all such counterparts shall together constitute but one and the same Guarantee.

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        IN WITNESS WHEREOF the parties hereto have duly executed and delivered this Guarantee as of the date first written above.

    CPI PREFERRED EQUITY LTD.

 

 

Per:

 

  

        Name:    
        Title:    

 

 

Per:

 

 

        Name:    
        Title:    

 

 

ATLANTIC POWER CORPORATION

 

 

Per:

 

 

        Name:    
        Title:    

 

 

Per:

 

  

        Name:    
        Title:    

 

 

CIBC MELLON TRUST COMPANY

 

 

Per:

 

  

        Name:    
        Title:    

 

 

Per:

 

  

        Name:    
        Title:    

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SCHEDULE A

        The Trustee shall invest the funds in Authorized Investments in its name in accordance with a direction from the Guarantor. Any direction from the Guarantor to the Trustee shall be in writing and shall be provided to the Trustee no later than 9:00 a.m. on the day on which the investment is to be made. Any such direction received by the Trustee after 9:00 a.m. or received on a non-Business Day, shall be deemed to have been given prior to 9:00 a.m. the next Business Day. For the purpose hereof, "Authorized Investments" means short term interest bearing or discount debt obligations issued or guaranteed by the Government of Canada or a Province or a Canadian chartered bank (which may include an Affiliate or related party of the Trustee) provided that such obligation is rated at least R1 (middle) by DBRS Inc. or an equivalent rating service.

Note:    Authorized Investments that are not short term interest bearing or discount debt obligations issued or guaranteed by the Government of Canada or a Province will be sold, if applicable or held to maturity one business day before the release of cash balances. Cash balances will be held in its deposit department, the deposit department of one of its Affiliates or the deposit department of a Canadian chartered bank at a rate of interest determined at the time of deposit.

        In the event that the Trustee does not receive a direction, or only a partial direction, the Trustee may hold cash balances and may, but need not, invest same in its deposit department, the deposit department of one of its Affiliates or the deposit department of a Canadian chartered bank; but the Trustee, its Affiliates or a Canadian chartered bank shall not be liable to account for any profit to any parties to this Agreement or to any other person or entity other than at a rate, if any, established from time to time, by the Trustee, its Affiliates or a Canadian chartered bank. For the purpose of this Schedule A, "Affiliate" means affiliated companies within the meaning of the Business Corporations Act (Ontario) ("OBCA"); and includes Canadian Imperial Bank of Commerce, CIBC Mellon Global Securities Services Company and Mellon Bank, N.A. and each of their affiliates within the meaning of the OBCA.

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AMONG:

        WHEREAS pursuant to the terms of this guarantee indenture (the "Guarantee") the Guarantor has agreed to guarantee in favour of the Holders (as defined below) the payment of the Preferred Share Obligations (as defined below), pursuant to the terms of the Series 2 Shares (as defined below);

        AND WHEREAS as at the date hereof, the Corporation has authorized for issuance up to 4,000,000 Series 2 Shares;

        AND WHEREAS as at the date hereof, the Corporation has authorized for issuance up to 4,000,000 Series 3 Shares;

        AND WHEREAS the Series 2 Shares, are on certain terms and conditions convertible to Series 3 Shares, and the Series 3 Shares are on certain terms and conditions convertible to Series 2 Shares;

        AND WHEREAS all necessary acts and proceedings have been done and taken and all necessary resolutions have been passed to authorize the execution and delivery of this Guarantee and to make the same legal, valid and binding upon the Guarantor;

        AND WHEREAS the foregoing recitals are made as representations and statements of fact by the Guarantor and not by the Security Trustee;

        NOW THEREFORE THIS GUARANTEE WITNESSES that for good and valuable consideration (the receipt and sufficiency of which are hereby acknowledged by each of the parties), the parties hereto agree as follows:


ARTICLE 1
DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION

1.1   Definitions

        For all purposes of this Guarantee, except as otherwise expressly provided or unless the context otherwise requires:

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        The following terms shall have the following meanings:

        "ABCA" means the Business Corporations Act (Alberta);

        "affiliate" has the meaning ascribed thereto in National Instrument 45-106—Prospectus and Registration Exemptions.

        "Board of Directors" means the board of directors of the Guarantor or any duly authorized committee of that board.

        "Board Resolution" means a copy of a resolution certified by an officer of the Guarantor to have been duly passed by the Board of Directors and to be in full force and effect on the applicable date of such certification, and delivered to the Security Trustee.

        "Business Day" means a day other than a Saturday, a Sunday or any other day that is a statutory or civid holiday in the place wehre the Corporation has its head office.

        "Corporate Trust Office" means the office of the Security Trustee, at which at any particular time its corporate trust business shall be principally administered, which office on the date of execution of this Guarantee is located at [600, 530 - 8th Avenue S.W., Calgary, Alberta T2P 3S8].

        "Event of Default" has the meaning specified in Section 4.2.

        "Guaranteed Obligations" has the meaning specified in Section 3.5;

        "Guarantor Order" or "Guarantor Request" means a written request or order signed in the name of the Guarantor by an officer of the Guarantor, and delivered to the Security Trustee.

        "Holders" means, the registered holders of the Series 2 Shares from time to time, provided that, in determining whether the Holders of the requisite percentage of the aggregate Liquidation Amount of outstanding Series 2 Shares have given any request, notice, consent or waiver hereunder, "Holders" shall not include the Guarantor or any affiliate of the Guarantor.

        "Liquidation Amount" means an amount equal to $25.00 per Series 2 Share plus an amount equal to all declared and unpaid dividends up to, but excluding, the date fixed for payment or distribution.

        "Officers' Certificate" means a certificate signed by an officer of the Guarantor, and delivered to the Security Trustee.

        "Opinion of Counsel" means a written opinion of counsel, who may be counsel for the Guarantor, including an employee of the Guarantor, and who shall be acceptable to the Security Trustee.

        "Person" means an individual, a corporation, a partnership, an association, a trust or any other entity or organization, including a government or political subdivision or an agency or instrumentality thereof.

        "Preferred Share Obligations" means all financial liabilities and obligations of the Corporation to the Holders in respect of the Series 2 Shares including or in respect of (i) any declared and unpaid dividends on the Series 2 Shares, (ii) the Redemption Price and all declared and unpaid dividends up to but excluding the date fixed for redemption with respect to Series 2 Shares called for redemption, and (iii) the Liquidation Amount payable on the Series 2 Shares upon a voluntary or involuntary dissolution, liquidation or winding up of the Corporation, without regard to the amount of assets of the Corporation available for distribution.

        "Redemption Price" means $25.00 per Series 2 Share redeemed.

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        "Responsible Officer", when used with respect to the Security Trustee, means the chairman or any vice-chairman of the board of directors of the Security Trustee, the chairman or any vice-chairman of the executive committee of the board of directors of the Security Trustee, and the chairman of the trust committee, the president, any vice president, the secretary, any assistant secretary, the treasurer, any assistant treasurer, any trust officer or assistant trust officer, the controller or any assistant controller and any other officer of the Security Trustee customarily performing functions similar to those performed by any of the above-designated officers, and also means, with respect to a particular corporate trust matter, any other officer to whom such matter is referred because of his knowledge of and familiarity with the particular subject.

        "Senior Indebtedness" shall mean the principal of and the interest and premium (or any other amounts payable thereunder), if any, on:

unless in each case it is provided by the terms of the instrument creating or evidencing such indebtedness, liabilities or obligations that such indebtedness, liabilities or obligations are pari passu with or subordinate in right of payment to the Preferred Share Obligations.

        "Series 2 Shares" means the Cumulative Rate Reset Preferred Shares, Series 2 of the Corporation.

        "Series 3 Shares" means the Cumulative Floating Rate Preferred Shares, Series 3 of the Corporation.

1.2   Compliance Certificates and Opinions

        Upon any application or request by the Guarantor to the Security Trustee to take any action under any provision of this Guarantee, the Guarantor shall furnish to the Security Trustee an Officers' Certificate stating that all conditions precedent, if any, provided for in this Guarantee (including any covenant compliance with which constitutes a condition precedent) relating to the proposed action have been complied with and an Opinion of Counsel stating that in the opinion of such counsel all such conditions precedent, if any, have been complied with, except that in the case of any such application or request as to which the furnishing of such documents is specifically required by any provision of this Guarantee relating to such particular application or request, no additional certificate or opinion need be furnished.

        In addition to the foregoing, every certificate or opinion with respect to compliance with a covenant or condition provided for in this Guarantee (other than as otherwise specified herein) shall include:

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1.3   Form of Documents Delivered to Security Trustee

        In any case where several matters are required to be certified by, or covered by an opinion of, any specified Person, it is not necessary that all such matters be certified by, or covered by the opinion of, only one such Person, or that they be so certified or covered by only one document, but one such Person may certify or give an opinion with respect to some matters and one or more other such Persons as to other matters, and any such Person may certify or give an opinion as to such matters in one or several documents.

        Any certificate or opinion of an officer of the Guarantor may be based, insofar as it relates to legal matters, upon a certificate or opinion of, or representations by, counsel, unless such officer knows, or in the exercise of reasonable care should know that the certificate or opinion or representations with respect to the matters upon which his or her certificate or opinion is based are erroneous. Any such certificate or Opinion of Counsel may be based, insofar as it relates to factual matters, upon a certificate or opinion of, or representations by, an officer or officers of the Guarantor stating that the information with respect to such factual matters is in the possession of the Guarantor, unless such counsel knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to such matters are erroneous.

        Where any Person is required to make, give or execute two or more applications, requests, consents, certificates, statements, opinions or other instruments under this Guarantee, they may, but need not, be consolidated and form one instrument.

1.4   Acts of Holders

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1.5   Notices, Etc. to Security Trustee and Guarantor

        Any request, demand, authorization, direction, notice, consent, waiver or Act of Holders or other documents provided or permitted by this Guarantee to be made upon, given or furnished to, or filed with,

        Any delivery made or facsimile sent on a day other than a Business Day, or after 3:00 p.m. (Calgary time) on a Business Day, shall be deemed to be received on the next following Business Day. Anything mailed shall not be deemed to have been given until it is actually received. The Guarantor or the Corporation may from time to time notify the Security Trustee of a change in address or facsimile number which thereafter, until changed by like notice, shall be the address or facsimile number of the Guarantor or the Corporation for all purposes of this Guarantee.

1.6   Notice to Holders; Waiver

        Where this Guarantee provides for notice of any event to the Holders of Series 2 Shares by the Guarantor or the Security Trustee, such notice shall be sufficiently given (unless otherwise herein expressly provided) if in writing and mailed, first-class postage prepaid, to each such Holder affected by such event, at the Holder's address as it appears in the list of Holders as provided by the Corporation, not later than the latest date, and not earlier than the earliest date, prescribed for the giving of such

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notice or in any other manner from time to time permitted by applicable laws, including, without limitation, internet-based or other electronic communications. In any case where notice to the Holders of Series 2 Shares is given by mail, neither the accidental failure to mail such notice, nor any defect in any notice so mailed, to any particular Holder shall affect the sufficiency of such notice with respect to other Holders of Series 2 Shares, but upon such failure to mail or such defect in any notice so mailed being discovered, the notice (as corrected to address any defects) shall be mailed forthwith to such Holder. Any notice mailed to a Holder in the manner herein prescribed shall be conclusively deemed to have been received by such Holder, whether or not such Holder actually receives such notice.

        Any request, demand, authorization, direction, notice, consent or waiver required or permitted under this Guarantee shall be in the English language.

        Where this Guarantee provides for notice in any manner, such notice may be waived in writing by the Person entitled to receive such notice, either before or after the event, and such waiver shall be the equivalent of such notice. Waivers of notice by Holders shall be filed with the Security Trustee, but such filing shall not be a condition precedent to the validity of any action taken in reliance upon such waiver.

1.7   Effect of Headings and Table of Contents

        The Article and Section headings herein and the Table of Contents are for convenience only and shall not affect the construction hereof.

1.8   Successors and Assigns

        All covenants and agreements in this Guarantee by the Guarantor shall bind its successors and assigns, whether so expressed or not.

1.9   Separability Clause

        In case any provision in this Guarantee shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

1.10 Governing Law

        This Guarantee shall be governed by and construed in accordance with the laws of the Province of Alberta and the federal laws of Canada applicable therein.

1.11 No Recourse Against Others

        A director, officer, employee or shareholder, as such, of the Guarantor shall not have any liability for any obligations of the Guarantor under this Guarantee or for any claim based on, in respect of or by reason of such obligations or its creation.

1.12 Multiple Originals

        The parties may sign any number of copies of this Guarantee. Each signed copy shall be an original, but all of them together represent the same agreement. One signed copy is enough to prove this Guarantee.

1.13 Language

        Les parties aux présentes ont exigé que Ia présente convention ainsi que tous les documents et avis qui s'y rattachent et/ou qui en découleront soient rediges et exécutés en langue anglaise. The parties hereto have required that this Guarantee and all documents and notices related thereto be drafted and executed in English.

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ARTICLE 2
GUARANTEE

2.1   Guarantee

        The Guarantor irrevocably and unconditionally guarantees in favour of the Holders the due and punctual payment of the Preferred Share Obligations (without duplication of amounts theretofore paid by or on behalf of the Corporation), regardless of any defense (except for the defense of payment by the Corporation), right of setoff or counterclaim which the Guarantor may have or assert. The Guarantor's obligation to pay a Preferred Share Obligation may be satisfied by (i) direct payment to the Holders or (ii) payment to the Holders through the facilities of the Security Trustee. The Guarantor shall give prompt written notice to the Security Trustee in the event it makes a direct payment to the Holders hereunder.

2.2   Waiver of Notice

        The Guarantor hereby waives notice of acceptance of this Guarantee.

2.3   Guarantee Absolute

        The Guarantor guarantees that the Preferred Share Obligations will be paid strictly in accordance with the terms of the Series 2 Shares and this Guarantee within the time required by Section 2.1 regardless of any law, regulation or order now or hereafter in effect in any jurisdiction affecting any such terms or the rights of the Holders with respect thereto. The liability of the Guarantor under this Guarantee shall be absolute and unconditional irrespective of:

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it being the intent of the Guarantor that its obligations in respect of Preferred Share Obligations shall be absolute and unconditional under all circumstances and shall not be discharged except by payment in full of the Preferred Share Obligations. The Holders shall not be bound or obliged to exhaust their recourse against the Corporation or any other persons or to take any other action before being entitled to demand payment from the Guarantor hereunder.

        There shall be no obligation of the Holders to give notice to, or obtain the consent of, the Guarantor with respect to the happening of any of the foregoing.

2.4   Continuing Guarantee

        This Guarantee shall apply to and secure any ultimate balance due or remaining due to the Holders in respect of the Preferred Share Obligations and shall be binding as an absolute and continuing obligation of the Guarantor. This Guarantee shall continue to be effective or be reinstated, as the case may be, if at any time payment of any of the Preferred Share Obligations must or may be rescinded, is declared or may become voidable, or must or may otherwise be returned by the Holders for any reason, including the insolvency, bankruptcy, dissolution or reorganization of the Corporation or upon or as a result of the appointment of a custodian, receiver, trustee or other officer with similar powers with respect to the Corporation or any substantial part of its property, all as though such payment had not been made. If at any time the Corporation is precluded from making payment when due in respect of any Preferred Share Obligations by reason of the provisions of the ABCA or otherwise, such amounts shall nonetheless be deemed to be due and payable by the Corporation to the Holders for all purposes of this Guarantee and the Preferred Share Obligations shall be immediately due and payable to the Holders. This is a guarantee of payment, and not merely a deficiency or collection guarantee.

2.5   Rights of Holders

        The Guarantor expressly acknowledges that: (i) this Guarantee will be deposited with the Security Trustee to be held for the benefit of the Holders; and (ii) the Security Trustee has the right to enforce this Guarantee on behalf of the Holders.

2.6   Guarantee of Payment

        If the Corporation shall fail to pay any of the Preferred Share Obligations when due, the Guarantor shall pay to the Holders the Preferred Share Obligations immediately after demand made in writing by one or more Holders or the Security Trustee, but in any event within 15 days of any failure by the Corporation to pay the Preferred Share Obligations when due, without any evidence that the Holders or the Security Trustee have demanded that the Corporation or the Guarantor pay any of the Preferred Share Obligations or that the Corporation has failed to do so.

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2.7   Subrogation

        The Guarantor shall have no right of subrogation in respect of any payment made to the Holders hereunder until such time as the Preferred Share Obligations have been fully satisfied. In the case of the liquidation, dissolution, winding-up or bankruptcy of the Corporation (whether voluntary or involuntary), or if the Corporation makes an arrangement or compromise or proposal with its creditors, the Holders shall have the right to rank for their full claim and to receive all dividends or other payments in respect thereof until their claims have been paid in full, and the Guarantor shall continue to be liable to the Holders for any balance which may be owing to the Holders by the Corporation. The Preferred Share Obligations shall not, however, be released, discharged, limited or affected by the failure or omission of the Holders to prove the whole or part of any claim against the Corporation. If any amount is paid to the Guarantor on account of any subrogation arising hereunder at any time when the Preferred Share Obligations have not been fully satisfied, such amount shall be held in trust for the benefit of the Holders and shall forthwith be paid to the Holders to be credited and applied against the Preferred Share Obligations.

2.8   Independent Obligations

        The Guarantor acknowledges that its obligations hereunder are independent of the obligations of the Corporation with respect to the Series 2 Shares and that the Guarantor shall be liable as principal and as debtor hereunder to make payment of the Preferred Share Obligations pursuant to the terms of this Guarantee notwithstanding the occurrence of any event referred to in subsections (a) through (l), inclusive, of Section 2.3, if the Holders should make a demand upon the Guarantor. The Guarantor will pay the Preferred Share Obligations without regard to any equities between it and the Corporation or any defence or right of set-off, compensation, abatement, combination of accounts or cross-claim that it or the Corporation may have.

2.9   Guarantor to Investigate Financial Condition of the Corporation

        The Guarantor acknowledges that it has fully informed itself about the financial condition of the Corporation. The Guarantor assumes full responsibility for keeping fully informed of the financial condition of the Corporation and all other circumstances affecting the Corporation's ability to pay the Preferred Share Obligations.


ARTICLE 3
SUBORDINATION OF OBLIGATIONS TO SENIOR INDEBTEDNESS

3.1   Applicability of Article

        The obligations of the Guarantor hereunder shall be subordinate and subject in right of payment, to the extent and in the manner hereinafter set forth in the following sections of this Article 3, to the prior payment in full, of all Senior Indebtedness of the Guarantor and the Security Trustee and each Holder of Series 2 Shares as a condition to and by acceptance of the benefits conferred hereby agrees to and shall be bound by the provisions of this Article 3.

3.2   Order of Payment

        Upon any distribution of the assets of the Guarantor on any dissolution, winding up, liquidation or reorganization of the Guarantor (whether in bankruptcy, insolvency or receivership proceedings, or upon an "assignment for the benefit of creditors" or any other marshalling of the assets and liabilities of the Guarantor, or otherwise):

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3.3   Subrogation to Rights of Holders of Senior Indebtedness

        Subject to the payment in full of all Senior Indebtedness, the Holders of the Series 2 Shares shall be subrogated to the rights of the holders of Senior Indebtedness to receive payments or distributions of assets of the Guarantor (to the extent of the application thereto of such payments or other assets which would have been received by the Holders of the Series 2 Shares but for the provisions hereof) until the Preferred Share Obligations shall be paid in full, and no such payments or distributions to the Holders of the Series 2 Shares of cash, property or securities, which otherwise would be payable or distributable to the holders of the Senior Indebtedness, shall, as between the Guarantor, its creditors (other than the holders of Senior Indebtedness), and the Holders of Series 2 Shares, be deemed to be a payment by the Guarantor to the holders of the Senior Indebtedness or on account of the Senior Indebtedness, it being understood that the provisions of this Article 3 are and are intended solely for the purpose of defining the relative rights of the Holders of the Series 2 Shares, on the one hand, and the holders of Senior Indebtedness, on the other hand.

3.4   Pari Passu Ranking

        Notwithstanding anything herein contained to the contrary, the obligations of the Guarantor hereunder rank on a pro rata and pari passu basis with the obligations of the Guarantor under the Guarantee Indenture dated    •    , 2011 among the Guarantor, the Corporation and CIBC Mellon Trust Company relating to the 4.85% cumulative redeemable preferred shares, Series 1 of the Corporation and with any other obligations of the Guarantor in respect of similar guarantees that may be provided by the Guarantor in respect of other series of cumulative redeemable preferred shares of the Corporation (collectively, the "Guaranteed Obligations"), including, without limitation, the guarantee provided by the Guarantor in respect of the Series 3 Shares.

3.5   Obligation to Pay Not Impaired

        Nothing contained in this Article 3 or elsewhere in this Guarantee or in the Series 2 Shares is intended to or shall impair, as between the Guarantor, its creditors (other than the holders of Senior Indebtedness), and the Holders of the Series 2 Shares, the obligation of the Guarantor, which is absolute and unconditional, to pay to the Holders of the Series 2 Shares the Preferred Share Obligations in accordance herewith, as and when the same shall become due and payable in accordance with this Guarantee, or affect the relative rights of the Holders of the Series 2 Shares and creditors of the Guarantor other than the holders of the Senior Indebtedness, nor shall anything herein or therein prevent the Security Trustee or the Holder of any Series 2 Share from exercising all remedies otherwise permitted by applicable law upon default under this Guarantee, subject to the rights, if any, under this Article 3 of the holders of Senior Indebtedness in respect of cash, property or securities of the Guarantor received upon the exercise of any such remedy.

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3.6   No Payment if Senior Indebtedness In Default

        Upon the maturity of any Senior Indebtedness by lapse of time, acceleration or otherwise, then, except as provided in Section 3.6, all principal of and interest on all such matured Senior Indebtedness shall first be paid in full, or shall first have been duly provided for, before any payment is made on account of the Preferred Share Obligations.

        In case of default with respect to any Senior Indebtedness permitting the holders thereof to accelerate the maturity thereof, unless and until such default shall have been cured or waived or shall have ceased to exist, no payment (by purchase of the Series 2 Shares or otherwise) shall be made by the Guarantor with respect to the Preferred Share Obligations and neither the Security Trustee nor the Holders of Series 2 Shares shall be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including without limitation by set-off, combination of accounts or otherwise in any manner whatsoever) on account of the Preferred Share Obligations after the happening of such a default (except as provided in Section 3.8), and unless and until such default shall have been cured or waived or shall have ceased to exist, such payments shall be held in trust for the benefit of, and, if and when such Senior Indebtedness shall have become due and payable, shall be paid over to, the holders of the Senior Indebtedness or their representative or representatives or to the trustee or trustees under any indenture under which any instruments evidencing an amount of the Senior Indebtedness remaining unpaid until all such Senior Indebtedness shall have been paid in full, after giving effect to any concurrent payment of distribution to the holders of such Senior Indebtedness.

        The fact that any payment hereunder is prohibited by this Section 3.5 shall not prevent the failure to make such payment from being an Event of Default hereunder.

3.7   Payment on Series 2 Shares Permitted

        Nothing contained in this Article 3 or elsewhere in this Guarantee, or in any of the Series 2 Shares, shall affect the obligation of the Guarantor to make, or prevent the Guarantor from making, at any time except during the pendency of any dissolution, winding up or liquidation of the Guarantor or reorganization proceedings specified in Section 3.2 affecting the affairs of the Guarantor, any payment on account of the Preferred Share Obligations, except that the Guarantor shall not make any such payment other than as contemplated by this Article 3, if it is in default in payment of any Senior Indebtedness. The fact that any such payment is prohibited by this Section 3.6 shall not prevent the failure to make such payment from being an Event of Default hereunder. Nothing contained in this Article 3 or elsewhere in this Guarantee, or in any of the Series 2 Shares, shall prevent the application by the Security Trustee of any moneys deposited with the Security Trustee hereunder for the purpose so deposited, to the payment of or on account of the Preferred Share Obligations unless and until the Security Trustee shall have received written notice from the Guarantor or from the holder of Senior Indebtedness or from the representative of any such holder of default with respect to any Senior Indebtedness permitting the holders thereof to accelerate the maturity thereof.

3.8   Confirmation of Subordination

        As a condition to the benefits conferred hereby on each Holder of Series 2 Shares, each such Holder by acceptance thereof authorizes and directs the Security Trustee on the Holder's behalf to take such action as may be necessary or appropriate to effectuate the subordination as provided in this Article 3 and appoints the Security Trustee as the Holder's attorney-in-fact for any and all such purposes. Upon request of the Guarantor, and upon being furnished with an Officers' Certificate stating that one or more named persons are holders of Senior Indebtedness, or the representative or representatives of such holders, or the trustee or trustees under which any instrument evidencing such Senior Indebtedness may have been issued, and specifying the amount and nature of such Senior

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Indebtedness, the Security Trustee shall enter into a written agreement or agreements with the Guarantor and the person or persons named in such Officers' Certificate providing that such person or persons are entitled to all the rights and benefits of this Article 3 as the holder or holders, representative or representatives, or trustee or trustees of the Senior Indebtedness specified in such Officers' Certificate and in such agreement. Such agreement shall be conclusive evidence that the indebtedness specified therein is Senior Indebtedness, however, nothing herein shall impair the rights of any holder of Senior Indebtedness who has not entered into such an agreement.

3.9   Security Trustee May Hold Senior Indebtedness

        The Security Trustee is entitled to all the rights set forth in this Article 3 with respect to any Senior Indebtedness at the time held by it, to the same extent as any other holder of Senior Indebtedness, and nothing in this Guarantee deprives the Security Trustee of any of its rights as such holder.

3.10 Rights of Holders of Senior Indebtedness Not Impaired

        No right of any present or future holder of any Senior Indebtedness to enforce the subordination herein will at any time or in any way be prejudiced or impaired by any act or failure to act on the part of the Guarantor or by any non-compliance by the Guarantor with the terms, provisions and covenants of this Guarantee, regardless of any knowledge thereof which any such holder may have or be otherwise charged with.

3.11 Altering the Senior Indebtedness

        The holders of the Senior Indebtedness have the right to extend, renew, modify or amend the terms of the Senior Indebtedness or any security therefor and to release, sell or exchange such security and otherwise to deal freely with the Guarantor, all without notice to or consent of the Holders of the Series 2 Shares or the Security Trustee and without affecting the liabilities and obligations of the parties to this Guarantee or the Holders of the Series 2 Shares or the Security Trustee.

3.12 Additional Indebtedness

        This Guarantee does not restrict the Guarantor from incurring any indebtedness for borrowed money or otherwise or mortgaging, pledging or charging its properties to secure any indebtedness.


ARTICLE 4
TERMINATION AND REMEDIES

4.1   Termination of Guarantee

        This Guarantee shall terminate upon the occurrence of the following events:

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        Upon termination of this Guarantee the Security Trustee shall, upon request of the Guarantor, provide to the Guarantor written documentation acknowledging the termination of this Guarantee.

        Notwithstanding the termination of this Guarantee, the obligations of the Guarantor to the Security Trustee under Section 5.3 shall survive.

4.2   Suits for Enforcement by the Security Trustee

        In the event that the Guarantor fails to pay the Preferred Share Obligations as required (an "Event of Default") pursuant to the terms of this Guarantee, the Holders may institute judicial proceedings for the collection of the moneys so due and unpaid, may prosecute such proceeding to judgment or final decree and may enforce the same against the Corporation and/or the Guarantor and may collect the moneys adjudged or decreed to be payable in the manner provided by law out of the property of the Guarantor.

        If an Event of Default occurs and is continuing, the Security Trustee may in its discretion proceed to protect and enforce its rights, and the rights of the Holders, upon being indemnified and funded to its satisfaction by the Holders, by such appropriate judicial proceedings as the Security Trustee shall deem most effectual to protect and enforce any such rights, whether for the specific enforcement of any covenant or agreement in this Guarantee or in aid of the exercise of any power granted herein, or to enforce any other proper remedy.

4.3   Security Trustee May File Proofs of Claim

        In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Guarantor or the property of the Guarantor, the Security Trustee shall be entitled and empowered, by intervention in such proceeding or otherwise,

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Holder to make such payments to the Security Trustee and, in the event that the Security Trustee shall consent to the making of such payments directly to the Holders, to pay to the Security Trustee all amounts due to it hereunder including, without limitation, the reasonable compensation, expenses, disbursements and advances of the Security Trustee in or about the execution of its trust, or otherwise in relation hereto, with interest thereon as herein provided.

        Nothing herein contained shall be deemed to authorize the Security Trustee to authorize or consent to or accept or adopt on behalf of any Holder any plan of reorganization, arrangement, adjustment or composition affecting the Series 2 Shares or the rights of any Holder thereof or to authorize the Security Trustee to vote in respect of the claim of any Holder in any such proceeding.

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4.4   Security Trustee May Enforce Claims Without Possession of Series 2 Shares

        All rights of action and claims under this Guarantee may be prosecuted and enforced by the Security Trustee without the possession of any of the Series 2 Shares in any proceeding relating thereto, and any such proceeding instituted by the Security Trustee shall be brought in its own name as trustee of an express trust, and any recovery of judgment shall, after provision for the payment of the reasonable compensation, expenses, disbursements and advances of the Security Trustee, its agents and counsel, be for the rateable benefit of the Holders of the Series 2 Shares in respect of which such judgment has been recovered.

4.5   Application of Money Collected

        Any money collected by the Security Trustee pursuant to this Article shall be applied in the following order:

4.6   Limitation on Suits

        No Holder of any outstanding Series 2 Shares shall have any right to institute any proceeding, judicial or otherwise, with respect to this Guarantee, or for the appointment of a receiver or trustee, or for any other remedy hereunder, unless:

it being understood and intended that no one or more of such Holders shall have any right in any manner whatever by virtue of, or by availing of, any provision of this Guarantee to affect, disturb or prejudice the rights of any other Holders of the outstanding Series 2 Shares, or to obtain or to seek to obtain priority or preference over any other of such Holders or to enforce any right under this Guarantee, except in the manner herein provided and for the equal and rateable benefit of all Holders of the outstanding Series 2 Shares.

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4.7   Restoration of Rights and Remedies

        If the Security Trustee or any Holder has instituted any proceeding to enforce any right or remedy under this Guarantee and such proceeding has been discontinued or abandoned for any reason, or has been determined adversely to the Security Trustee or to such Holder, then and in every such case, subject to any determination in such proceeding, the Guarantor, the Security Trustee and the Holders of Series 2 Shares shall be restored severally and respectively to their former positions hereunder and thereafter all rights and remedies of the Security Trustee and the Holders shall continue as though no such proceeding had been instituted.

4.8   Rights and Remedies Cumulative

        No right or remedy herein conferred upon or reserved to the Security Trustee or to the Holders of Series 2 Shares is intended to be exclusive of any other right or remedy, and every right and remedy shall, to the extent permitted by law, be cumulative and in addition to every other right and remedy given hereunder or now or hereafter existing at law or in equity or otherwise. The assertion or employment of any right or remedy hereunder, or otherwise, shall not prevent the concurrent assertion or employment of any other appropriate right or remedy.

4.9   Delay or Omission Not Waiver

        No delay or omission of the Security Trustee or of any Holder of any Series 2 Shares to exercise any right or remedy accruing upon an Event of Default shall impair any such right or remedy or constitute a waiver of any such Event of Default or an acquiescence therein. Every right and remedy given by this Article or by law to the Security Trustee or to the Holders may be exercised from time to time, and as often as may be deemed expedient, by the Security Trustee or by the Holders, as the case may be.

4.10 Control by Holders

        The Holders representing not less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares affected by an Event of Default (determined as one class) shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Security Trustee, or exercising any trust or power conferred on the Security Trustee, with respect to this Guarantee, provided that in each case:

4.11 Waiver of Stay or Extension Laws

        The Guarantor covenants (to the extent that it may lawfully do so) that it will not at any time insist upon or plead, or in any manner whatsoever claim or take the benefit or advantage of, any stay or extension law wherever enacted, now or at any time hereafter in force, which may affect the covenants or the performance of this Guarantee, and the Guarantor (to the extent that it may lawfully do so) hereby expressly waives all benefit or advantage of any such law and covenants that it will not hinder, delay or impede the execution of any power herein granted to the Security Trustee, but will suffer and permit the execution of every such power as though no such law had been enacted.

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4.12 Undertaking for Costs

        All parties to this Guarantee agree, and each Holder of any Series 2 Shares by acceptance thereof and by acceptance of the benefits hereof shall be deemed to have agreed, that any court may in its discretion require, in any suit for the enforcement of any right or remedy under this Guarantee, or in any suit against the Security Trustee for any action taken, suffered or omitted by it as Security Trustee, the filing by any party litigant in such suit of an undertaking to pay the costs of such suit and that such court may in its discretion assess reasonable costs, including reasonable lawyers' fees, against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant; but the provisions of this Section shall not apply to (i) any suit instituted by the Guarantor, (ii) any suit instituted by the Security Trustee, (iii) any suit instituted by any Holder, or group of Holders, holding in the aggregate more than 25% of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares, or (iv) any suit instituted by any Holder for the enforcement of the payment of the Preferred Share Obligations.


ARTICLE 5
THE SECURITY TRUSTEE

5.1   Certain Duties and Responsibilities

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5.2   Certain Rights of Security Trustee

        Subject to the provisions of Section 5.1:

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5.3   Protection of Security Trustee

        By way of supplement to the provisions of any law for the time being relating to trustees, it is expressly declared and agreed as follows:

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5.4   Security Trustee Not Required to Give Security

        The Security Trustee shall not be required to give security for the execution of the trusts or its conduct or administration hereunder.

5.5   No Person Dealing with Security Trustee Need Enquire

        No person dealing with the Security Trustee shall be concerned to enquire whether the powers that the Security Trustee is purporting to exercise have become exercisable, or whether any money remains due upon the Series 2 Shares or to see to the application of any money paid to the Security Trustee.

5.6   May Hold Series 2 Shares

        Subject to applicable law, the Security Trustee or any other agent of the Guarantor, in its individual or in any other capacity, may become the owner or pledgee of the Series 2 Shares and, subject to Section 5.8, may otherwise deal with the Guarantor with the same rights it would have if it were not the Security Trustee, and without being liable to account for any profit made thereby.

5.7   Moneys Held in Trust

5.8   Conflict of Interest

5.9   Corporate Security Trustee Required; Eligibility

        There shall at all times be a Security Trustee hereunder which shall be a corporation resident or authorized to carry on the business of a trust company in the Province of Alberta. Neither the Guarantor nor any affiliate of the Guarantor shall serve as Security Trustee. If at any time the Security Trustee shall cease to be eligible in accordance with the provisions of this Section, the Security Trustee shall resign immediately in the manner and with the effect hereinafter specified in this Article.

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5.10 Resignation and Removal; Appointment of Successor

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5.11 Acceptance of Appointment by Successor

5.12 Merger, Consolidation, Amalgamation or Succession to Business

        Any corporation into which the Security Trustee may be merged or with which it may be consolidated or amalgamated, or any corporation resulting from any merger, consolidation or amalgamation to which the Security Trustee shall be a party, or any corporation succeeding to all or substantially all of the corporate trust business of the Security Trustee, shall be the successor of the Security Trustee hereunder, provided such corporation shall be otherwise qualified and eligible under this Article, without the execution or filing of any paper or instrument or any further act on the part of any of the parties hereto.

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5.13 Not Bound to Act

        The Security Trustee shall retain the right not to act and shall not be liable for refusing to act if, due to a lack of information or for any other reason whatsoever, the Security Trustee, in its sole judgment, determines that such act might cause it to be in non-compliance with any applicable anti-money laundering or anti-terrorist legislation, regulation or guideline. Further, should the Security Trustee, in its sole judgment, determine at any time that its acting under this Guarantee has resulted in its being in non-compliance with any applicable anti-money laundering, or anti-terrorist legislation, regulation or guideline, then it shall have the right to resign on 10 days written notice to the Guarantor, provided that (i) the Security Trustee's written notice shall describe the circumstances of such non-compliance; and (ii) if such circumstances are rectified to the Security Trustee's satisfaction, acting reasonably, within such 10 day period, then such resignation shall not be effective.

5.14 Security Trustee's Privacy Clause

        The parties acknowledge that federal and/or provincial legislation that addresses the protection of individuals' personal information (collectively, "Privacy Laws") applies to obligations and activities under this Guarantee. Despite any other provision of this Guarantee, no party shall take or direct any action that would contravene, or cause the other to contravene, applicable Privacy Laws. The Guarantor shall, prior to transferring or causing to be transferred personal information to the Security Trustee, obtain and retain required consents of the relevant individuals to the collection, use and disclosure of their personal information, or shall have determined that such consents either have previously been given upon which the parties can rely or are not required under the Privacy Laws. The Security Trustee shall use commercially reasonable efforts to ensure that its services hereunder comply with Privacy Laws. Specifically, the Security Trustee agrees: (i) to have a designated chief privacy officer; (ii) to maintain policies and procedures to protect personal information and to receive and respond to any privacy complaint or inquiry; (iii) to use personal information solely for the purposes of providing its services under or ancillary to this Guarantee and not to use it for any other purpose except with the consent of or direction from the Guarantor or the individual involved; (iv) not to sell or otherwise improperly disclose personal information to any third party; and (v) to employ administrative, physical and technological safeguards to reasonably secure and protect personal information against loss, theft, or unauthorized access, use or modification.

5.15 Compensation and Reimbursement

        The Guarantor agrees:

        The Security Trustee's remuneration, shall be payable out of any funds coming into the possession of the Security Trustee in priority to any payment of the Preferred Share Obligations. The said remuneration shall continue to be payable whether or not this Guarantee shall be in the course of administration by or under the direction of a court of competent jurisdiction. Any amount due under this Section and unpaid within 30 days after demand for such payment by the Security Trustee, shall bear interest at the then current rate of interest charged by the Security Trustee to its corporate customers. This Section 5.15 shall survive the removal or termination of the Security Trustee and the termination of this Guarantee.

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ARTICLE 6
HOLDERS' LISTS AND REPORTS BY SECURITY TRUSTEE AND GUARANTOR

6.1   List of Holders

        The Corporation shall furnish or cause to be furnished to the Security Trustee at such times as the Security Trustee may request in writing, within five Business Days after the receipt by the Corporation of any such request, a list, in such form as the Security Trustee may reasonably require, of the names and addresses of the Holders as of a date not more than 15 days prior to the time such list is furnished, in each case to the extent such information is in the possession or control of the Corporation and is not identical to a previously supplied list of Holders or has not otherwise been received by the Security Trustee in its capacity as such. The Security Trustee may destroy any list of Holders previously given to it on receipt of a new list of Holders.

        The Corporation shall provide the Security Trustee with an updated list of Holders within 15 days of the Guarantor or any affiliate of the Guarantor becoming a Holder.

6.2   Access to list of Holders

        A Holder may, upon payment to the Security Trustee of a reasonable fee, require the Security Trustee to furnish within 10 days after receiving the affidavit or statutory declaration referred to below, a list setting out (i) the name and address of every Holder of Series 2 Shares, (ii) the aggregate number of Series 2 Shares owned by each such Holder, and (iii) the aggregate number of the Series 2 Shares then outstanding, each as shown on the records of the Security Trustee on the day that the affidavit or statutory declaration is delivered to the Security Trustee. The affidavit or statutory declaration, as the case may be, shall contain (i) the name and address of the Holder, (ii) where the applicant is a corporation, its name and address for service, (iii) a statement that the list will not be used except in connection with an effort to influence the voting of the Holders of Series 2 Shares, or any other matter relating to the Guarantee, and (iv) such other undertaking as may be required by applicable law. Where the Holder is a corporation, the affidavit or statutory declaration shall be made by a director or officer of the corporation.

6.3   Communications to Holders

        The rights of Holders to communicate with other Holders with respect to their rights under this Guarantee and the corresponding rights and privileges of the Security Trustee, shall be governed by applicable law.

        Every Holder of Series 2 Shares, by receiving and holding the same, agrees with the Guarantor and the Security Trustee that neither the Guarantor nor the Security Trustee nor any agent of either of them shall be held accountable by reason of any disclosure of information as to the names and addresses of Holders made pursuant to the terms hereof or applicable law.


ARTICLE 7
CONVEYANCE, TRANSFER OR LEASE

7.1   Conveyance, Transfer or Lease; Only on Certain Terms

        The Guarantor shall not convey, transfer or lease all or substantially all of its properties and assets to any Person, unless:

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        This Section shall only apply to conveyances, leases and transfers by the Guarantor as transferor or lessor.

7.2   Successor Person Substituted

        Upon any conveyance, transfer or lease of all or substantially all of the properties and assets of the Guarantor to any Person in accordance with Section 7.1, the successor Person to which such conveyance, transfer or lease is made shall succeed to, and be substituted for, and may exercise every right and power of, the Guarantor under this Guarantee with the same effect as if such successor Person had been named as the Guarantor herein, and in the event of any such conveyance or transfer, the Guarantor (which term shall for this purpose mean the Person named as the "Guarantor" in the first paragraph of this Guarantee or any successor Person which shall theretofore become such in the manner described in Section 7.1), except in the case of a lease, shall be discharged of all obligations and covenants under this Guarantee.

7.3   Sale of Common Shares of the Corporation and/or Limited Partnership Units of Capital Power Income L.P.

        The Guarantor shall not, directly or indirectly, convey, transfer or otherwise dispose of any limited partnership units of Capital Power Income L.P., common shares of CPI Investments Inc., common shares of CPI Income Services Ltd. or common shares of the Corporation beneficially owned by it, if any such conveyance, transfer or disposition would cause the Guarantor to cease to be an affiliate of Capital Power Income L.P. or the Corporation, unless all of the beneficial holders of limited partnership units of Capital Power Income L.P., common shares of CPI Investments Inc., common shares of CPI Income Services Ltd. and common shares of the Corporation (other than the Guarantor) shall have entered into a guarantee indenture with the Trustee, substantially similar to this guarantee indenture and in form and substance satisfactory to the Trustee, acting reasonably, whereby such holders irrevocably and unconditionally guarantee in favour of the Holders the due and punctual payment of the Preferred Share Obligations on the same terms and conditions as set forth herein.


ARTICLE 8
SUPPLEMENTAL INDENTURES

8.1   Supplemental Indentures Without Consent of Holders

        Without the consent of any Holders, the Guarantor, when authorized by or pursuant to a Board Resolution, and the Security Trustee, at any time and from time to time may enter into one or more indentures supplemental hereto, in form satisfactory to the Security Trustee, for any of the following purposes:

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8.2   Supplemental Guarantees with Consent of Holders

        With the consent of either (i) the Holders representing not less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares, by Act of such Holders delivered to the Guarantor and the Security Trustee, or (ii) if a meeting of the Holders is called for obtaining such consent, Holders representing not less than a majority of the aggregate Liquidation Amount of all Series 2 Shares represented at such meeting and voting in respect of such consent, the Guarantor, when authorized by or pursuant to a Board Resolution, and the Security Trustee may enter into an indenture or indentures supplemental hereto for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of this Guarantee or of modifying in any manner the rights of the Holders under this Guarantee; provided, however, that no such supplemental indenture shall, without the consent of the Holders representing not less than 662/3% of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares or, if a meeting of the Holders is called for obtaining such consent, Holders representing not less than a majority of the aggregate Liquidation Amount of all Series 2 Shares represented at such meeting and voting in respect of such consent, as the case may be,

8.3   Execution of Supplemental Guarantees

        In executing, or accepting the additional trusts created by, any supplemental indenture permitted by this Article or the modifications thereby of the trusts created by this Guarantee, the Security Trustee shall be entitled to receive, and shall be fully protected in acting and relying upon, an Opinion of

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Counsel stating that the execution of such supplemental indenture is authorized or permitted by this Guarantee. The Security Trustee may, but shall not be obligated to, enter into any such supplemental indenture which affects the Security Trustee's own rights, duties or immunities under this Guarantee or otherwise.

8.4   Effect of Supplemental Indentures

        Upon the execution of any supplemental indenture under this Article, this Guarantee shall be modified in accordance therewith, and such supplemental indenture shall form a part of this Guarantee for all purposes.

8.5   Notice of Supplemental Guarantees

        Promptly after the execution by the Guarantor and the Security Trustee of any supplemental indenture pursuant to the provisions of Section 8.2, the Guarantor shall give notice thereof to the Holders of each of the outstanding Series 2 Shares affected, in the manner provided for in Section 1.6, setting forth in general terms the substance of such supplemental indenture.


ARTICLE 9
COVENANTS

9.1   Existence

        Subject to Article 7 the Guarantor will do or cause to be done all things necessary to preserve and keep in full force and effect its existence and the rights and franchises of the Guarantor and its subsidiaries; provided, however, that the Guarantor shall not be required to preserve any such right or franchise if the Guarantor shall determine that the preservation thereof is no longer desirable in the conduct of the business of the Guarantor.

9.2   Security Trustee Not Required to Verify Liquidation Amount

        The Guarantor will not require the Security Trustee to calculate or verify the Liquidation Amount. When requested by the Security Trustee, the Liquidation Amount shall be specified in an Officer's Certificate and delivered to the Security Trustee.

9.3   Restriction on Dividends

        The Guarantor hereby covenants and agrees that if and for so long as either the board of directors of the Corporation has failed to declare, or the Corporation has failed to pay, dividends on the Series 2 Shares, in each case, in accordance with the share conditions attaching thereto, then the Guarantor shall not declare or pay any dividends on its shares or make any distributions or pay any dividends on securities of any successor entity of the Guarantor.


ARTICLE 10
PURCHASE OF SERIES 2 SHARES

10.1 Purchase of Series 2 Shares

        Subject to applicable law, at any time when the Guarantor is not in default hereunder, the Guarantor may purchase Series 2 Shares at any price in the market (including purchases from or through an investment dealer or a firm holding membership on a recognized stock exchange) or by tender available to all Holders of Series 2 Shares or by private contract, in each case in accordance with the terms of the Series 2 Shares.

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ARTICLE 11
MEETINGS OF HOLDERS OF SERIES 2 SHARES

11.1 Purposes for Which Meetings May Be Called

        A meeting of the Holders of the Series 2 Shares may be called at any time and from time to time pursuant to the provisions of this Article for one or more of the following purposes:

11.2 Call, Notice and Place of Meetings

11.3 Persons Entitled to Vote at Meetings

        To be entitled to vote at any meeting of Holders of Series 2 Shares, a Person shall be (1) a Holder of one or more outstanding Series 2 Shares, or (2) a Person appointed by an instrument in writing as proxy for a Holder or Holders of one or more outstanding Series 2 Shares by such Holder of Holders. The only Persons who shall be entitled to be present or to speak at any meeting of Holders of Series 2 Shares shall be the Persons entitled to vote at such meeting and their respective counsel, any representatives of the Security Trustee and its counsel, and any representatives of the Guarantor and its counsel.

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11.4 Quorum; Action

        The Holders representing not less than 25% of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares shall constitute a quorum for a meeting of Holders of Series 2 Shares; provided, however, that, if any action is to be taken at such meeting with respect to a consent or waiver which this Guarantee expressly provides may be given by the Holders of not less than a specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares, the Persons entitled to vote such specified percentage in aggregate amount of the outstanding Series 2 Shares shall constitute a quorum. In the absence of a quorum within 30 minutes of the time appointed for any such meeting, the meeting shall, if convened at the request of Holders of Series 2 Shares, be dissolved. In any other case the meeting may be adjourned for a period of not less than 10 days as determined by the chairman of the meeting prior to the adjournment of such meeting. In the absence of a quorum at any such adjourned meeting, such adjourned meeting may be further adjourned for a period of not less than 10 days as determined by the chairman of the meeting prior to the adjournment of such adjourned meeting. Notice of the reconvening of any adjourned meeting shall be given as provided in Section 11.2(a), except that such notice need be given only once not less than five days prior to the date on which the meeting is scheduled to be reconvened.

        Subject to the foregoing, at the reconvening of any meeting adjourned for lack of a quorum, the Holders of Series 2 Shares entitled to vote at such meeting present in person or by proxy shall constitute a quorum for the taking of any action set forth in the notice of the original meeting.

        Except as limited by the proviso to Section 8.2, any resolution presented to a meeting or adjourned meeting duly reconvened at which a quorum is present as aforesaid may be adopted by the affirmative vote of the Holders representing not less than a majority of the aggregate Liquidation Amount of Series 2 Shares represented at such meeting in person or by proxy; provided, however, that, except as limited by the proviso to Section 8.2, any resolution with respect to any request, demand, authorization, direction, notice, consent, waiver or other action which this Guarantee expressly provides may be made, given or taken by the Holders of a specified percentage, which is less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares may be adopted at a meeting or an adjourned meeting duly reconvened and at which a quorum is present as aforesaid by the affirmative vote of the Holders of not less than such specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares.

        Any resolution passed or decision taken at any meeting of Holders of Series 2 Shares duly held in accordance with this Section shall be binding on all the Holders of Series 2 Shares, whether or not present or represented at the meeting.

        Notwithstanding the foregoing provisions of this Section 11.4, if any action is to be taken at a meeting of Holders of Series 2 Shares with respect to any request, demand, authorization, direction, notice, consent, waiver or other action that this Guarantee expressly provides may be made, given or taken by the Holders of a specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series 2 Shares affected thereby:

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11.5 Determination of Voting Rights; Conduct and Adjournment of Meetings

11.6 Counting Votes and Recording Action of Meetings

        The vote upon any resolution submitted to any meeting of Holders of Series 2 Shares shall be by written ballot(s) on which shall be subscribed the signatures of the Holders of Series 2 Shares or of their representatives by proxy and the number of outstanding Series 2 Shares held or represented by them. The permanent chairman of the meeting shall appoint two inspectors of votes who shall count all votes cast at the meeting for or against any resolution and who shall make and file with the secretary of the meeting their verified written reports in duplicate of all votes cast at the meeting. A record, at least in duplicate, of the proceedings of each meeting of Holders of Series 2 Shares shall be prepared by the Secretary of the meeting and there shall be attached to said record the original reports of the inspectors of votes on any vote by ballot taken thereat and affidavits by one or more persons having knowledge of the facts setting forth a copy of the notice of the meeting and showing that said notice was given as provided in Section 11.2 and, if applicable, Section 11.4. Each copy shall be signed and verified by the affidavits of the permanent chairman and secretary of the meeting and one such copy shall be delivered to the Guarantor, and another to the Security Trustee to be preserved by the Security Trustee, the latter to have attached thereto the ballots voted at the meeting. Any record so signed and verified shall be conclusive evidence of the matters therein stated.

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        This Guarantee may be executed in any number of counterparts, each of which so executed shall be deemed to be an original, but all such counterparts shall together constitute but one and the same Guarantee.

        IN WITNESS WHEREOF the parties hereto have duly executed and delivered this Guarantee as of the date first written above.

    CPI PREFERRED EQUITY LTD.

 

 

Per:

 


 
        Name:    
        Title:    

 

 

Per:

 


 
        Name:    
        Title:    

 

 

ATLANTIC POWER CORPORATION

 

 

Per:

 


 
        Name:    
        Title:    

 

 

Per:

 


 
        Name:    
        Title:    

 

 

COMPUTERSHARE TRUST COMPANY OF CANADA

 

 

Per:

 


 
        Name:    
        Title:    

 

 

Per:

 


 
        Name:    
        Title:    

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SCHEDULE A

        The Security Trustee shall invest the funds in Authorized Investments in its name in accordance with a direction from the Guarantor. Any direction from the Guarantor to the Security Trustee shall be in writing and shall be provided to the Security Trustee no later than 9:00 a.m. (Calgary time) on the day on which the investment is to be made. Any such direction received by the Security Trustee after 9:00 a.m. (Calgary time) or received on a Saturday, a Sunday or any other day that is a statutory or civic holiday in the cities of Calgary or Toronto shall be deemed to have been given prior to 9:00 a.m. (Calgary time) on the next day that is not a Saturday, a Sunday or any other day that is a statutory or civic holiday in the cities of Calgary or Toronto. For the purpose hereof, "Authorized Investments" means short term interest bearing or discount debt obligations issued or guaranteed by the Government of Canada or a Province of Canada or a Canadian chartered bank provided that such obligation is rated at least R1 (middle) by DBRS Inc. or an equivalent rating service.

Note:    Authorized Investments that are not short term interest bearing or discount debt obligations issued or guaranteed by the Government of Canada or a Province will be sold, if applicable or held to maturity one business day before the release of cash balances. Cash balances will be held in the Security Trustee's deposit department, the deposit department of one of its Affiliates or the deposit department of a Canadian chartered bank at a rate of interest determined at the time of deposit. For the purpose of this Schedule A, "Affiliate" means affiliated companies within the meaning of the Business Corporations Act (Ontario).

        In the event that the Security Trustee does not receive a direction, or only receives a partial direction, subject to Section 5.8(b) the Security Trustee may hold cash balances and may, but need not, invest same in its deposit department, or the deposit department of a Canadian chartered bank; but the Security Trustee, or a Canadian chartered bank shall not be liable to account for any profit to any parties to this Agreement or to any other person or entity in excess of the interest rate from time to time of the account for deposits pursuant to Section 5.8.

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AMONG:

        WHEREAS pursuant to the terms of this guarantee indenture (the "Guarantee") the Guarantor has agreed to guarantee in favour of the Holders (as defined below) the payment of the Preferred Share Obligations (as defined below), pursuant to the terms of the Series 3 Shares (as defined below);

        AND WHEREAS as at the date hereof, the Corporation has authorized for issuance up to 4,000,000 Series 3 Shares;

        AND WHEREAS as at the date hereof, the Corporation has authorized for issuance up to 4,000,000 Series 2 Shares;

        AND WHEREAS the Series 3 Shares, are on certain terms and conditions convertible to Series 2 Shares, and the Series 2 Shares are on certain terms and conditions convertible to Series 3 Shares;

        AND WHEREAS all necessary acts and proceedings have been done and taken and all necessary resolutions have been passed to authorize the execution and delivery of this Guarantee and to make the same legal, valid and binding upon the Guarantor;

        AND WHEREAS the foregoing recitals are made as representations and statements of fact by the Guarantor and not by the Security Trustee;

        NOW THEREFORE THIS GUARANTEE WITNESSES that for good and valuable consideration (the receipt and sufficiency of which are hereby acknowledged by each of the parties), the parties hereto agree as follows:


ARTICLE 1
DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION

1.1   Definitions

        For all purposes of this Guarantee, except as otherwise expressly provided or unless the context otherwise requires:

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        The following terms shall have the following meanings:

        "ABCA" means the Business Corporations Act (Alberta);

        "affiliate" has the meaning ascribed thereto in National Instrument 45-106—Prospectus and Registration Exemptions.

        "Board of Directors" means the board of directors of the Guarantor or any duly authorized committee of that board.

        "Board Resolution" means a copy of a resolution certified by an officer of the Guarantor to have been duly passed by the Board of Directors and to be in full force and effect on the applicable date of such certification, and delivered to the Security Trustee.

        "Business Day" means a day other than a Saturday, a Sunday or any other day that is a statutory or civic holiday in the place where the Corporation has its head office.

        "Corporate Trust Office" means the office of the Security Trustee, at which at any particular time its corporate trust business shall be principally administered, which office on the date of execution of this Guarantee is located at [600, 530 - 8th Avenue S.W., Calgary, Alberta T2P 3S8].

        "Event of Default" has the meaning specified in Section 4.2.

        "Guaranteed Obligations" has the meaning specified in Section 3.5;

        "Guarantor Order" or "Guarantor Request" means a written request or order signed in the name of the Guarantor by an officer of the Guarantor, and delivered to the Security Trustee.

        "Holders" means, the registered holders of the Series 3 Shares from time to time, provided that, in determining whether the Holders of the requisite percentage of the aggregate Liquidation Amount of outstanding Series 3 Shares have given any request, notice, consent or waiver hereunder, "Holders" shall not include the Guarantor or any affiliate of the Guarantor.

        "Liquidation Amount" means an amount equal to $25.00 per Series 3 Share plus an amount equal to all declared and unpaid dividends up to, but excluding, the date fixed for payment or distribution.

        "Officers' Certificate" means a certificate signed by an officer of the Guarantor, and delivered to the Security Trustee.

        "Opinion of Counsel" means a written opinion of counsel, who may be counsel for the Guarantor, including an employee of the Guarantor, and who shall be acceptable to the Security Trustee.

        "Person" means an individual, a corporation, a partnership, an association, a trust or any other entity or organization, including a government or political subdivision or an agency or instrumentality thereof.

        "Preferred Share Obligations" means all financial liabilities and obligations of the Corporation to the Holders in respect of the Series 3 Shares including or in respect of (i) any declared and unpaid dividends on the Series 3 Shares, (ii) the Redemption Price and all declared and unpaid dividends up to but excluding the date fixed for redemption with respect to Series 3 Shares called for redemption, and (iii) the Liquidation Amount payable on the Series 3 Shares upon a voluntary or involuntary dissolution, liquidation or winding up of the Corporation, without regard to the amount of assets of the Corporation available for distribution.

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        "Redemption Price" means (i) $25.00 per Series 3 Share redeemed if such share is redeemed on any Series 3 Conversion Date; or (ii) $25.50 per Series 3 Share redeemed if such share is redeemed on any date after December 31, 2014 that is not a Series 3 Conversion Date.

        "Responsible Officer", when used with respect to the Security Trustee, means the chairman or any vice-chairman of the board of directors of the Security Trustee, the chairman or any vice-chairman of the executive committee of the board of directors of the Security Trustee, and the chairman of the trust committee, the president, any vice president, the secretary, any assistant secretary, the treasurer, any assistant treasurer, any trust officer or assistant trust officer, the controller or any assistant controller and any other officer of the Security Trustee customarily performing functions similar to those performed by any of the above-designated officers, and also means, with respect to a particular corporate trust matter, any other officer to whom such matter is referred because of his knowledge of and familiarity with the particular subject.

        "Senior Indebtedness" shall mean the principal of and the interest and premium (or any other amounts payable thereunder), if any, on:

unless in each case it is provided by the terms of the instrument creating or evidencing such indebtedness, liabilities or obligations that such indebtedness, liabilities or obligations are pari passu with or subordinate in right of payment to the Preferred Share Obligations.

        "Series 2 Shares" means the Cumulative Rate Reset Preferred Shares, Series 2 of the Corporation.

        "Series 3 Conversion Date" means December 31, 2019 and December 31 every fifth year thereafter.

        "Series 3 Shares" means the Cumulative Floating Rate Preferred Shares, Series 3 of the Corporation.

1.2   Compliance Certificates and Opinions

        Upon any application or request by the Guarantor to the Security Trustee to take any action under any provision of this Guarantee, the Guarantor shall furnish to the Security Trustee an Officers' Certificate stating that all conditions precedent, if any, provided for in this Guarantee (including any covenant compliance with which constitutes a condition precedent) relating to the proposed action have been complied with and an Opinion of Counsel stating that in the opinion of such counsel all such conditions precedent, if any, have been complied with, except that in the case of any such application or request as to which the furnishing of such documents is specifically required by any provision of this Guarantee relating to such particular application or request, no additional certificate or opinion need be furnished.

        In addition to the foregoing, every certificate or opinion with respect to compliance with a covenant or condition provided for in this Guarantee (other than as otherwise specified herein) shall include:

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1.3   Form of Documents Delivered to Security Trustee

        In any case where several matters are required to be certified by, or covered by an opinion of, any specified Person, it is not necessary that all such matters be certified by, or covered by the opinion of, only one such Person, or that they be so certified or covered by only one document, but one such Person may certify or give an opinion with respect to some matters and one or more other such Persons as to other matters, and any such Person may certify or give an opinion as to such matters in one or several documents.

        Any certificate or opinion of an officer of the Guarantor may be based, insofar as it relates to legal matters, upon a certificate or opinion of, or representations by, counsel, unless such officer knows, or in the exercise of reasonable care should know that the certificate or opinion or representations with respect to the matters upon which his or her certificate or opinion is based are erroneous. Any such certificate or Opinion of Counsel may be based, insofar as it relates to factual matters, upon a certificate or opinion of, or representations by, an officer or officers of the Guarantor stating that the information with respect to such factual matters is in the possession of the Guarantor, unless such counsel knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to such matters are erroneous.

        Where any Person is required to make, give or execute two or more applications, requests, consents, certificates, statements, opinions or other instruments under this Guarantee, they may, but need not, be consolidated and form one instrument.

1.4   Acts of Holders

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1.5   Notices, Etc. to Security Trustee and Guarantor

        Any request, demand, authorization, direction, notice, consent, waiver or Act of Holders or other documents provided or permitted by this Guarantee to be made upon, given or furnished to, or filed with,

        Any delivery made or facsimile sent on a day other than a Business Day, or after 3:00 p.m. (Calgary time) on a Business Day, shall be deemed to be received on the next following Business Day. Anything mailed shall not be deemed to have been given until it is actually received. The Guarantor or the Corporation may from time to time notify the Security Trustee of a change in address or facsimile number which thereafter, until changed by like notice, shall be the address or facsimile number of the Guarantor or the Corporation for all purposes of this Guarantee.

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1.6   Notice to Holders; Waiver

        Where this Guarantee provides for notice of any event to the Holders of Series 3 Shares by the Guarantor or the Security Trustee, such notice shall be sufficiently given (unless otherwise herein expressly provided) if in writing and mailed, first-class postage prepaid, to each such Holder affected by such event, at the Holder's address as it appears in the list of Holders as provided by the Corporation, not later than the latest date, and not earlier than the earliest date, prescribed for the giving of such notice or in any other manner from time to time permitted by applicable laws, including, without limitation, internet-based or other electronic communications. In any case where notice to the Holders of Series 3 Shares is given by mail, neither the accidental failure to mail such notice, nor any defect in any notice so mailed, to any particular Holder shall affect the sufficiency of such notice with respect to other Holders of Series 3 Shares, but upon such failure to mail or such defect in any notice so mailed being discovered, the notice (as corrected to address any defects) shall be mailed forthwith to such Holder. Any notice mailed to a Holder in the manner herein prescribed shall be conclusively deemed to have been received by such Holder, whether or not such Holder actually receives such notice.

        Any request, demand, authorization, direction, notice, consent or waiver required or permitted under this Guarantee shall be in the English language.

        Where this Guarantee provides for notice in any manner, such notice may be waived in writing by the Person entitled to receive such notice, either before or after the event, and such waiver shall be the equivalent of such notice. Waivers of notice by Holders shall be filed with the Security Trustee, but such filing shall not be a condition precedent to the validity of any action taken in reliance upon such waiver.

1.7   Effect of Headings and Table of Contents

        The Article and Section headings herein and the Table of Contents are for convenience only and shall not affect the construction hereof.

1.8   Successors and Assigns

        All covenants and agreements in this Guarantee by the Guarantor shall bind its successors and assigns, whether so expressed or not.

1.9   Separability Clause

        In case any provision in this Guarantee shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

1.10 Governing Law

        This Guarantee shall be governed by and construed in accordance with the laws of the Province of Alberta and the federal laws of Canada applicable therein.

1.11 No Recourse Against Others

        A director, officer, employee or shareholder, as such, of the Guarantor shall not have any liability for any obligations of the Guarantor under this Guarantee or for any claim based on, in respect of or by reason of such obligations or its creation.

1.12 Multiple Originals

        The parties may sign any number of copies of this Guarantee. Each signed copy shall be an original, but all of them together represent the same agreement. One signed copy is enough to prove this Guarantee.

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1.13 Language

        Les parties aux présentes ont exigé que Ia présente convention ainsi que tous les documents et avis qui s'y rattachent et/ou qui en découleront soient rediges et exécutés en langue anglaise. The parties hereto have required that this Guarantee and all documents and notices related thereto be drafted and executed in English.


ARTICLE 2
GUARANTEE

2.1   Guarantee

        The Guarantor irrevocably and unconditionally guarantees in favour of the Holders the due and punctual payment of the Preferred Share Obligations (without duplication of amounts theretofore paid by or on behalf of the Corporation), regardless of any defense (except for the defense of payment by the Corporation), right of setoff or counterclaim which the Guarantor may have or assert. The Guarantor's obligation to pay a Preferred Share Obligation may be satisfied by (i) direct payment to the Holders or (ii) payment to the Holders through the facilities of the Security Trustee. The Guarantor shall give prompt written notice to the Security Trustee in the event it makes a direct payment to the Holders hereunder.

2.2   Waiver of Notice

        The Guarantor hereby waives notice of acceptance of this Guarantee.

2.3   Guarantee Absolute

        The Guarantor guarantees that the Preferred Share Obligations will be paid strictly in accordance with the terms of the Series 3 Shares and this Guarantee within the time required by Section 2.1 regardless of any law, regulation or order now or hereafter in effect in any jurisdiction affecting any such terms or the rights of the Holders with respect thereto. The liability of the Guarantor under this Guarantee shall be absolute and unconditional irrespective of:

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it being the intent of the Guarantor that its obligations in respect of Preferred Share Obligations shall be absolute and unconditional under all circumstances and shall not be discharged except by payment in full of the Preferred Share Obligations. The Holders shall not be bound or obliged to exhaust their recourse against the Corporation or any other persons or to take any other action before being entitled to demand payment from the Guarantor hereunder.

        There shall be no obligation of the Holders to give notice to, or obtain the consent of, the Guarantor with respect to the happening of any of the foregoing.

2.4   Continuing Guarantee

        This Guarantee shall apply to and secure any ultimate balance due or remaining due to the Holders in respect of the Preferred Share Obligations and shall be binding as an absolute and continuing obligation of the Guarantor. This Guarantee shall continue to be effective or be reinstated, as the case may be, if at any time payment of any of the Preferred Share Obligations must or may be rescinded, is declared or may become voidable, or must or may otherwise be returned by the Holders for any reason, including the insolvency, bankruptcy, dissolution or reorganization of the Corporation or upon or as a result of the appointment of a custodian, receiver, trustee or other officer with similar powers with respect to the Corporation or any substantial part of its property, all as though such payment had not been made. If at any time the Corporation is precluded from making payment when due in respect of any Preferred Share Obligations by reason of the provisions of the ABCA or otherwise, such amounts shall nonetheless be deemed to be due and payable by the Corporation to the Holders for all purposes of this Guarantee and the Preferred Share Obligations shall be immediately due and payable to the Holders. This is a guarantee of payment, and not merely a deficiency or collection guarantee.

2.5   Rights of Holders

        The Guarantor expressly acknowledges that: (i) this Guarantee will be deposited with the Security Trustee to be held for the benefit of the Holders; and (ii) the Security Trustee has the right to enforce this Guarantee on behalf of the Holders.

2.6   Guarantee of Payment

        If the Corporation shall fail to pay any of the Preferred Share Obligations when due, the Guarantor shall pay to the Holders the Preferred Share Obligations immediately after demand made in writing by one or more Holders or the Security Trustee, but in any event within 15 days of any failure by the Corporation to pay the Preferred Share Obligations when due, without any evidence that the Holders or the Security Trustee have demanded that the Corporation or the Guarantor pay any of the Preferred Share Obligations or that the Corporation has failed to do so.

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2.7   Subrogation

        The Guarantor shall have no right of subrogation in respect of any payment made to the Holders hereunder until such time as the Preferred Share Obligations have been fully satisfied. In the case of the liquidation, dissolution, winding-up or bankruptcy of the Corporation (whether voluntary or involuntary), or if the Corporation makes an arrangement or compromise or proposal with its creditors, the Holders shall have the right to rank for their full claim and to receive all dividends or other payments in respect thereof until their claims have been paid in full, and the Guarantor shall continue to be liable to the Holders for any balance which may be owing to the Holders by the Corporation. The Preferred Share Obligations shall not, however, be released, discharged, limited or affected by the failure or omission of the Holders to prove the whole or part of any claim against the Corporation. If any amount is paid to the Guarantor on account of any subrogation arising hereunder at any time when the Preferred Share Obligations have not been fully satisfied, such amount shall be held in trust for the benefit of the Holders and shall forthwith be paid to the Holders to be credited and applied against the Preferred Share Obligations.

2.8   Independent Obligations

        The Guarantor acknowledges that its obligations hereunder are independent of the obligations of the Corporation with respect to the Series 3 Shares and that the Guarantor shall be liable as principal and as debtor hereunder to make payment of the Preferred Share Obligations pursuant to the terms of this Guarantee notwithstanding the occurrence of any event referred to in subsections (a) through (l), inclusive, of Section 2.3, if the Holders should make a demand upon the Guarantor. The Guarantor will pay the Preferred Share Obligations without regard to any equities between it and the Corporation or any defence or right of set-off, compensation, abatement, combination of accounts or cross-claim that it or the Corporation may have.

2.9   Guarantor to Investigate Financial Condition of the Corporation

        The Guarantor acknowledges that it has fully informed itself about the financial condition of the Corporation. The Guarantor assumes full responsibility for keeping fully informed of the financial condition of the Corporation and all other circumstances affecting the Corporation's ability to pay the Preferred Share Obligations.


ARTICLE 3
SUBORDINATION OF OBLIGATIONS TO SENIOR INDEBTEDNESS

3.1   Applicability of Article

        The obligations of the Guarantor hereunder shall be subordinate and subject in right of payment, to the extent and in the manner hereinafter set forth in the following sections of this Article 3, to the prior payment in full, of all Senior Indebtedness of the Guarantor and the Security Trustee and each Holder of Series 3 Shares as a condition to and by acceptance of the benefits conferred hereby agrees to and shall be bound by the provisions of this Article 3.

3.2   Order of Payment

        Upon any distribution of the assets of the Guarantor on any dissolution, winding up, liquidation or reorganization of the Guarantor (whether in bankruptcy, insolvency or receivership proceedings, or upon an "assignment for the benefit of creditors" or any other marshalling of the assets and liabilities of the Guarantor, or otherwise):

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3.3   Subrogation to Rights of Holders of Senior Indebtedness

        Subject to the payment in full of all Senior Indebtedness, the Holders of the Series 3 Shares shall be subrogated to the rights of the holders of Senior Indebtedness to receive payments or distributions of assets of the Guarantor (to the extent of the application thereto of such payments or other assets which would have been received by the Holders of the Series 3 Shares but for the provisions hereof) until the Preferred Share Obligations shall be paid in full, and no such payments or distributions to the Holders of the Series 3 Shares of cash, property or securities, which otherwise would be payable or distributable to the holders of the Senior Indebtedness, shall, as between the Guarantor, its creditors (other than the holders of Senior Indebtedness), and the Holders of Series 3 Shares, be deemed to be a payment by the Guarantor to the holders of the Senior Indebtedness or on account of the Senior Indebtedness, it being understood that the provisions of this Article 3 are and are intended solely for the purpose of defining the relative rights of the Holders of the Series 3 Shares, on the one hand, and the holders of Senior Indebtedness, on the other hand.

3.4   Pari Passu Ranking

        Notwithstanding anything herein contained to the contrary, the obligations of the Guarantor hereunder rank on a pro rata and pari passu basis with the obligations of the Guarantor under the Guarantee Indenture dated    •    , 2011 among the Guarantor, the Corporation and CIBC Mellon Trust Company relating to the 4.85% cumulative redeemable preferred shares, Series 1 of the Corporation and with any other obligations of the Guarantor in respect of similar guarantees that may be provided by the Guarantor in respect of other series of cumulative redeemable preferred shares of the Corporation (collectively, the "Guaranteed Obligations"), including, without limitation, the guarantee provided by the Guarantor in respect of the Series 3 Shares.

3.5   Obligation to Pay Not Impaired

        Nothing contained in this Article 3 or elsewhere in this Guarantee or in the Series 3 Shares is intended to or shall impair, as between the Guarantor, its creditors (other than the holders of Senior Indebtedness), and the Holders of the Series 3 Shares, the obligation of the Guarantor, which is absolute and unconditional, to pay to the Holders of the Series 3 Shares the Preferred Share Obligations in accordance herewith, as and when the same shall become due and payable in accordance with this Guarantee, or affect the relative rights of the Holders of the Series 3 Shares and creditors of the Guarantor other than the holders of the Senior Indebtedness, nor shall anything herein or therein prevent the Security Trustee or the Holder of any Series 3 Share from exercising all remedies otherwise permitted by applicable law upon default under this Guarantee, subject to the rights, if any, under this Article 3 of the holders of Senior Indebtedness in respect of cash, property or securities of the Guarantor received upon the exercise of any such remedy.

3.6   No Payment if Senior Indebtedness In Default

        Upon the maturity of any Senior Indebtedness by lapse of time, acceleration or otherwise, then, except as provided in Section 3.6, all principal of and interest on all such matured Senior Indebtedness shall first be paid in full, or shall first have been duly provided for, before any payment is made on account of the Preferred Share Obligations.

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        In case of default with respect to any Senior Indebtedness permitting the holders thereof to accelerate the maturity thereof, unless and until such default shall have been cured or waived or shall have ceased to exist, no payment (by purchase of the Series 3 Shares or otherwise) shall be made by the Guarantor with respect to the Preferred Share Obligations and neither the Security Trustee nor the Holders of Series 3 Shares shall be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including without limitation by set-off, combination of accounts or otherwise in any manner whatsoever) on account of the Preferred Share Obligations after the happening of such a default (except as provided in Section 3.8), and unless and until such default shall have been cured or waived or shall have ceased to exist, such payments shall be held in trust for the benefit of, and, if and when such Senior Indebtedness shall have become due and payable, shall be paid over to, the holders of the Senior Indebtedness or their representative or representatives or to the trustee or trustees under any indenture under which any instruments evidencing an amount of the Senior Indebtedness remaining unpaid until all such Senior Indebtedness shall have been paid in full, after giving effect to any concurrent payment of distribution to the holders of such Senior Indebtedness.

        The fact that any payment hereunder is prohibited by this Section 3.5 shall not prevent the failure to make such payment from being an Event of Default hereunder.

3.7   Payment on Series 3 Shares Permitted

        Nothing contained in this Article 3 or elsewhere in this Guarantee, or in any of the Series 3 Shares, shall affect the obligation of the Guarantor to make, or prevent the Guarantor from making, at any time except during the pendency of any dissolution, winding up or liquidation of the Guarantor or reorganization proceedings specified in Section 3.2 affecting the affairs of the Guarantor, any payment on account of the Preferred Share Obligations, except that the Guarantor shall not make any such payment other than as contemplated by this Article 3, if it is in default in payment of any Senior Indebtedness. The fact that any such payment is prohibited by this Section 3.6 shall not prevent the failure to make such payment from being an Event of Default hereunder. Nothing contained in this Article 3 or elsewhere in this Guarantee, or in any of the Series 3 Shares, shall prevent the application by the Security Trustee of any moneys deposited with the Security Trustee hereunder for the purpose so deposited, to the payment of or on account of the Preferred Share Obligations unless and until the Security Trustee shall have received written notice from the Guarantor or from the holder of Senior Indebtedness or from the representative of any such holder of default with respect to any Senior Indebtedness permitting the holders thereof to accelerate the maturity thereof.

3.8   Confirmation of Subordination

        As a condition to the benefits conferred hereby on each Holder of Series 3 Shares, each such Holder by acceptance thereof authorizes and directs the Security Trustee on the Holder's behalf to take such action as may be necessary or appropriate to effectuate the subordination as provided in this Article 3 and appoints the Security Trustee as the Holder's attorney-in-fact for any and all such purposes. Upon request of the Guarantor, and upon being furnished with an Officers' Certificate stating that one or more named persons are holders of Senior Indebtedness, or the representative or representatives of such holders, or the trustee or trustees under which any instrument evidencing such Senior Indebtedness may have been issued, and specifying the amount and nature of such Senior Indebtedness, the Security Trustee shall enter into a written agreement or agreements with the Guarantor and the person or persons named in such Officers' Certificate providing that such person or persons are entitled to all the rights and benefits of this Article 3 as the holder or holders, representative or representatives, or trustee or trustees of the Senior Indebtedness specified in such Officers' Certificate and in such agreement. Such agreement shall be conclusive evidence that the indebtedness specified therein is Senior Indebtedness, however, nothing herein shall impair the rights of any holder of Senior Indebtedness who has not entered into such an agreement.

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3.9   Security Trustee May Hold Senior Indebtedness

        The Security Trustee is entitled to all the rights set forth in this Article 3 with respect to any Senior Indebtedness at the time held by it, to the same extent as any other holder of Senior Indebtedness, and nothing in this Guarantee deprives the Security Trustee of any of its rights as such holder.

3.10 Rights of Holders of Senior Indebtedness Not Impaired

        No right of any present or future holder of any Senior Indebtedness to enforce the subordination herein will at any time or in any way be prejudiced or impaired by any act or failure to act on the part of the Guarantor or by any non-compliance by the Guarantor with the terms, provisions and covenants of this Guarantee, regardless of any knowledge thereof which any such holder may have or be otherwise charged with.

3.11 Altering the Senior Indebtedness

        The holders of the Senior Indebtedness have the right to extend, renew, modify or amend the terms of the Senior Indebtedness or any security therefor and to release, sell or exchange such security and otherwise to deal freely with the Guarantor, all without notice to or consent of the Holders of the Series 3 Shares or the Security Trustee and without affecting the liabilities and obligations of the parties to this Guarantee or the Holders of the Series 3 Shares or the Security Trustee.

3.12 Additional Indebtedness

        This Guarantee does not restrict the Guarantor from incurring any indebtedness for borrowed money or otherwise or mortgaging, pledging or charging its properties to secure any indebtedness.


ARTICLE 4
TERMINATION AND REMEDIES

4.1   Termination of Guarantee

        This Guarantee shall terminate upon the occurrence of the following events:

        Upon termination of this Guarantee the Security Trustee shall, upon request of the Guarantor, provide to the Guarantor written documentation acknowledging the termination of this Guarantee.

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        Notwithstanding the termination of this Guarantee, the obligations of the Guarantor to the Security Trustee under Section 5.3 shall survive.

4.2   Suits for Enforcement by the Security Trustee

        In the event that the Guarantor fails to pay the Preferred Share Obligations as required (an "Event of Default") pursuant to the terms of this Guarantee, the Holders may institute judicial proceedings for the collection of the moneys so due and unpaid, may prosecute such proceeding to judgment or final decree and may enforce the same against the Corporation and/or the Guarantor and may collect the moneys adjudged or decreed to be payable in the manner provided by law out of the property of the Guarantor.

        If an Event of Default occurs and is continuing, the Security Trustee may in its discretion proceed to protect and enforce its rights, and the rights of the Holders, upon being indemnified and funded to its satisfaction by the Holders, by such appropriate judicial proceedings as the Security Trustee shall deem most effectual to protect and enforce any such rights, whether for the specific enforcement of any covenant or agreement in this Guarantee or in aid of the exercise of any power granted herein, or to enforce any other proper remedy.

4.3   Security Trustee May File Proofs of Claim

        In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Guarantor or the property of the Guarantor, the Security Trustee shall be entitled and empowered, by intervention in such proceeding or otherwise,

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Holder to make such payments to the Security Trustee and, in the event that the Security Trustee shall consent to the making of such payments directly to the Holders, to pay to the Security Trustee all amounts due to it hereunder including, without limitation, the reasonable compensation, expenses, disbursements and advances of the Security Trustee in or about the execution of its trust, or otherwise in relation hereto, with interest thereon as herein provided.

        Nothing herein contained shall be deemed to authorize the Security Trustee to authorize or consent to or accept or adopt on behalf of any Holder any plan of reorganization, arrangement, adjustment or composition affecting the Series 3 Shares or the rights of any Holder thereof or to authorize the Security Trustee to vote in respect of the claim of any Holder in any such proceeding.

4.4   Security Trustee May Enforce Claims Without Possession of Series 3 Shares

        All rights of action and claims under this Guarantee may be prosecuted and enforced by the Security Trustee without the possession of any of the Series 3 Shares in any proceeding relating thereto, and any such proceeding instituted by the Security Trustee shall be brought in its own name as trustee of an express trust, and any recovery of judgment shall, after provision for the payment of the reasonable compensation, expenses, disbursements and advances of the Security Trustee, its agents and

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counsel, be for the rateable benefit of the Holders of the Series 3 Shares in respect of which such judgment has been recovered.

4.5   Application of Money Collected

        Any money collected by the Security Trustee pursuant to this Article shall be applied in the following order:

4.6   Limitation on Suits

        No Holder of any outstanding Series 3 Shares shall have any right to institute any proceeding, judicial or otherwise, with respect to this Guarantee, or for the appointment of a receiver or trustee, or for any other remedy hereunder, unless:

it being understood and intended that no one or more of such Holders shall have any right in any manner whatever by virtue of, or by availing of, any provision of this Guarantee to affect, disturb or prejudice the rights of any other Holders of the outstanding Series 3 Shares, or to obtain or to seek to obtain priority or preference over any other of such Holders or to enforce any right under this Guarantee, except in the manner herein provided and for the equal and rateable benefit of all Holders of the outstanding Series 3 Shares.

4.7   Restoration of Rights and Remedies

        If the Security Trustee or any Holder has instituted any proceeding to enforce any right or remedy under this Guarantee and such proceeding has been discontinued or abandoned for any reason, or has

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been determined adversely to the Security Trustee or to such Holder, then and in every such case, subject to any determination in such proceeding, the Guarantor, the Security Trustee and the Holders of Series 3 Shares shall be restored severally and respectively to their former positions hereunder and thereafter all rights and remedies of the Security Trustee and the Holders shall continue as though no such proceeding had been instituted.

4.8   Rights and Remedies Cumulative

        No right or remedy herein conferred upon or reserved to the Security Trustee or to the Holders of Series 3 Shares is intended to be exclusive of any other right or remedy, and every right and remedy shall, to the extent permitted by law, be cumulative and in addition to every other right and remedy given hereunder or now or hereafter existing at law or in equity or otherwise. The assertion or employment of any right or remedy hereunder, or otherwise, shall not prevent the concurrent assertion or employment of any other appropriate right or remedy.

4.9   Delay or Omission Not Waiver

        No delay or omission of the Security Trustee or of any Holder of any Series 3 Shares to exercise any right or remedy accruing upon an Event of Default shall impair any such right or remedy or constitute a waiver of any such Event of Default or an acquiescence therein. Every right and remedy given by this Article or by law to the Security Trustee or to the Holders may be exercised from time to time, and as often as may be deemed expedient, by the Security Trustee or by the Holders, as the case may be.

4.10 Control by Holders

        The Holders representing not less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares affected by an Event of Default (determined as one class) shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Security Trustee, or exercising any trust or power conferred on the Security Trustee, with respect to this Guarantee, provided that in each case:

4.11 Waiver of Stay or Extension Laws

        The Guarantor covenants (to the extent that it may lawfully do so) that it will not at any time insist upon or plead, or in any manner whatsoever claim or take the benefit or advantage of, any stay or extension law wherever enacted, now or at any time hereafter in force, which may affect the covenants or the performance of this Guarantee, and the Guarantor (to the extent that it may lawfully do so) hereby expressly waives all benefit or advantage of any such law and covenants that it will not hinder, delay or impede the execution of any power herein granted to the Security Trustee, but will suffer and permit the execution of every such power as though no such law had been enacted.

4.12 Undertaking for Costs

        All parties to this Guarantee agree, and each Holder of any Series 3 Shares by acceptance thereof and by acceptance of the benefits hereof shall be deemed to have agreed, that any court may in its

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discretion require, in any suit for the enforcement of any right or remedy under this Guarantee, or in any suit against the Security Trustee for any action taken, suffered or omitted by it as Security Trustee, the filing by any party litigant in such suit of an undertaking to pay the costs of such suit and that such court may in its discretion assess reasonable costs, including reasonable lawyers' fees, against any party litigant in such suit, having due regard to the merits and good faith of the claims or defenses made by such party litigant; but the provisions of this Section shall not apply to (i) any suit instituted by the Guarantor, (ii) any suit instituted by the Security Trustee, (iii) any suit instituted by any Holder, or group of Holders, holding in the aggregate more than 25% of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares, or (iv) any suit instituted by any Holder for the enforcement of the payment of the Preferred Share Obligations.


ARTICLE 5
THE SECURITY TRUSTEE

5.1   Certain Duties and Responsibilities

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5.2   Certain Rights of Security Trustee

        Subject to the provisions of Section 5.1:

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5.3   Protection of Security Trustee

        By way of supplement to the provisions of any law for the time being relating to trustees, it is expressly declared and agreed as follows:

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5.4   Security Trustee Not Required to Give Security

        The Security Trustee shall not be required to give security for the execution of the trusts or its conduct or administration hereunder.

5.5   No Person Dealing with Security Trustee Need Enquire

        No person dealing with the Security Trustee shall be concerned to enquire whether the powers that the Security Trustee is purporting to exercise have become exercisable, or whether any money remains due upon the Series 3 Shares or to see to the application of any money paid to the Security Trustee.

5.6   May Hold Series 3 Shares

        Subject to applicable law, the Security Trustee or any other agent of the Guarantor, in its individual or in any other capacity, may become the owner or pledgee of the Series 3 Shares and, subject to Section 5.8, may otherwise deal with the Guarantor with the same rights it would have if it were not the Security Trustee, and without being liable to account for any profit made thereby.

5.7   Moneys Held in Trust

5.8   Conflict of Interest

5.9   Corporate Security Trustee Required; Eligibility

        There shall at all times be a Security Trustee hereunder which shall be a corporation resident or authorized to carry on the business of a trust company in the Province of Alberta. Neither the Guarantor nor any affiliate of the Guarantor shall serve as Security Trustee. If at any time the Security

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Trustee shall cease to be eligible in accordance with the provisions of this Section, the Security Trustee shall resign immediately in the manner and with the effect hereinafter specified in this Article.

5.10 Resignation and Removal; Appointment of Successor

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5.11 Acceptance of Appointment by Successor

5.12 Merger, Consolidation, Amalgamation or Succession to Business

        Any corporation into which the Security Trustee may be merged or with which it may be consolidated or amalgamated, or any corporation resulting from any merger, consolidation or

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amalgamation to which the Security Trustee shall be a party, or any corporation succeeding to all or substantially all of the corporate trust business of the Security Trustee, shall be the successor of the Security Trustee hereunder, provided such corporation shall be otherwise qualified and eligible under this Article, without the execution or filing of any paper or instrument or any further act on the part of any of the parties hereto.

5.13 Not Bound to Act

        The Security Trustee shall retain the right not to act and shall not be liable for refusing to act if, due to a lack of information or for any other reason whatsoever, the Security Trustee, in its sole judgment, determines that such act might cause it to be in non-compliance with any applicable anti-money laundering or anti-terrorist legislation, regulation or guideline. Further, should the Security Trustee, in its sole judgment, determine at any time that its acting under this Guarantee has resulted in its being in non-compliance with any applicable anti-money laundering, or anti-terrorist legislation, regulation or guideline, then it shall have the right to resign on 10 days written notice to the Guarantor, provided that (i) the Security Trustee's written notice shall describe the circumstances of such non-compliance; and (ii) if such circumstances are rectified to the Security Trustee's satisfaction, acting reasonably, within such 10 day period, then such resignation shall not be effective.

5.14 Security Trustee's Privacy Clause

        The parties acknowledge that federal and/or provincial legislation that addresses the protection of individuals' personal information (collectively, "Privacy Laws") applies to obligations and activities under this Guarantee. Despite any other provision of this Guarantee, no party shall take or direct any action that would contravene, or cause the other to contravene, applicable Privacy Laws. The Guarantor shall, prior to transferring or causing to be transferred personal information to the Security Trustee, obtain and retain required consents of the relevant individuals to the collection, use and disclosure of their personal information, or shall have determined that such consents either have previously been given upon which the parties can rely or are not required under the Privacy Laws. The Security Trustee shall use commercially reasonable efforts to ensure that its services hereunder comply with Privacy Laws. Specifically, the Security Trustee agrees: (i) to have a designated chief privacy officer; (ii) to maintain policies and procedures to protect personal information and to receive and respond to any privacy complaint or inquiry; (iii) to use personal information solely for the purposes of providing its services under or ancillary to this Guarantee and not to use it for any other purpose except with the consent of or direction from the Guarantor or the individual involved; (iv) not to sell or otherwise improperly disclose personal information to any third party; and (v) to employ administrative, physical and technological safeguards to reasonably secure and protect personal information against loss, theft, or unauthorized access, use or modification.

5.15 Compensation and Reimbursement

        The Guarantor agrees:

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        The Security Trustee's remuneration, shall be payable out of any funds coming into the possession of the Security Trustee in priority to any payment of the Preferred Share Obligations. The said remuneration shall continue to be payable whether or not this Guarantee shall be in the course of administration by or under the direction of a court of competent jurisdiction. Any amount due under this Section and unpaid within 30 days after demand for such payment by the Security Trustee, shall bear interest at the then current rate of interest charged by the Security Trustee to its corporate customers. This Section 5.15 shall survive the removal or termination of the Security Trustee and the termination of this Guarantee.


ARTICLE 6
HOLDERS' LISTS AND REPORTS BY SECURITY TRUSTEE AND GUARANTOR

6.1   List of Holders

        The Corporation shall furnish or cause to be furnished to the Security Trustee at such times as the Security Trustee may request in writing, within five Business Days after the receipt by the Corporation of any such request, a list, in such form as the Security Trustee may reasonably require, of the names and addresses of the Holders as of a date not more than 15 days prior to the time such list is furnished, in each case to the extent such information is in the possession or control of the Corporation and is not identical to a previously supplied list of Holders or has not otherwise been received by the Security Trustee in its capacity as such. The Security Trustee may destroy any list of Holders previously given to it on receipt of a new list of Holders.

        The Corporation shall provide the Security Trustee with an updated list of Holders within 15 days of the Guarantor or any affiliate of the Guarantor becoming a Holder.

6.2   Access to list of Holders

        A Holder may, upon payment to the Security Trustee of a reasonable fee, require the Security Trustee to furnish within 10 days after receiving the affidavit or statutory declaration referred to below, a list setting out (i) the name and address of every Holder of Series 3 Shares, (ii) the aggregate number of Series 3 Shares owned by each such Holder, and (iii) the aggregate number of the Series 3 Shares then outstanding, each as shown on the records of the Security Trustee on the day that the affidavit or statutory declaration is delivered to the Security Trustee. The affidavit or statutory declaration, as the case may be, shall contain (i) the name and address of the Holder, (ii) where the applicant is a corporation, its name and address for service, (iii) a statement that the list will not be used except in connection with an effort to influence the voting of the Holders of Series 3 Shares, or any other matter relating to the Guarantee, and (iv) such other undertaking as may be required by applicable law. Where the Holder is a corporation, the affidavit or statutory declaration shall be made by a director or officer of the corporation.

6.3   Communications to Holders

        The rights of Holders to communicate with other Holders with respect to their rights under this Guarantee and the corresponding rights and privileges of the Security Trustee, shall be governed by applicable law.

        Every Holder of Series 3 Shares, by receiving and holding the same, agrees with the Guarantor and the Security Trustee that neither the Guarantor nor the Security Trustee nor any agent of either of them shall be held accountable by reason of any disclosure of information as to the names and addresses of Holders made pursuant to the terms hereof or applicable law.

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ARTICLE 7
CONVEYANCE, TRANSFER OR LEASE

7.1   Conveyance, Transfer or Lease; Only on Certain Terms

        The Guarantor shall not convey, transfer or lease all or substantially all of its properties and assets to any Person, unless:

        This Section shall only apply to conveyances, leases and transfers by the Guarantor as transferor or lessor.

7.2   Successor Person Substituted

        Upon any conveyance, transfer or lease of all or substantially all of the properties and assets of the Guarantor to any Person in accordance with Section 7.1, the successor Person to which such conveyance, transfer or lease is made shall succeed to, and be substituted for, and may exercise every right and power of, the Guarantor under this Guarantee with the same effect as if such successor Person had been named as the Guarantor herein, and in the event of any such conveyance or transfer, the Guarantor (which term shall for this purpose mean the Person named as the "Guarantor" in the first paragraph of this Guarantee or any successor Person which shall theretofore become such in the manner described in Section 7.1), except in the case of a lease, shall be discharged of all obligations and covenants under this Guarantee.

7.3   Sale of Common Shares of the Corporation and/or Limited Partnership Units of Capital Power Income L.P.

        The Guarantor shall not, directly or indirectly, convey, transfer or otherwise dispose of any limited partnership units of Capital Power Income L.P., common shares of CPI Investments Inc., common shares of CPI Income Services Ltd. or common shares of the Corporation beneficially owned by it, if any such conveyance, transfer or disposition would cause the Guarantor to cease to be an affiliate of Capital Power Income L.P. or the Corporation, unless all of the beneficial holders of limited partnership units of Capital Power Income L.P., common shares of CPI Investments Inc., common shares of CPI Income Services Ltd. and common shares of the Corporation (other than the Guarantor) shall have entered into a guarantee indenture with the Trustee, substantially similar to this guarantee indenture and in form and substance satisfactory to the Trustee, acting reasonably, whereby such holders irrevocably and unconditionally guarantee in favour of the Holders the due and punctual payment of the Preferred Share Obligations on the same terms and conditions as set forth herein.

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ARTICLE 8
SUPPLEMENTAL INDENTURES

8.1   Supplemental Indentures Without Consent of Holders

        Without the consent of any Holders, the Guarantor, when authorized by or pursuant to a Board Resolution, and the Security Trustee, at any time and from time to time may enter into one or more indentures supplemental hereto, in form satisfactory to the Security Trustee, for any of the following purposes:

8.2   Supplemental Guarantees with Consent of Holders

        With the consent of either (i) the Holders representing not less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares, by Act of such Holders delivered to the Guarantor and the Security Trustee, or (ii) if a meeting of the Holders is called for obtaining such consent, Holders representing not less than a majority of the aggregate Liquidation Amount of all Series 3 Shares represented at such meeting and voting in respect of such consent, the Guarantor, when authorized by or pursuant to a Board Resolution, and the Security Trustee may enter into an indenture or indentures supplemental hereto for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of this Guarantee or of modifying in any manner the rights of the Holders under this Guarantee; provided, however, that no such supplemental indenture shall, without the consent of the Holders representing not less than 662/3% of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares or, if a meeting of the Holders is called for obtaining such consent, Holders representing not less than a majority of the aggregate Liquidation

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Amount of all Series 3 Shares represented at such meeting and voting in respect of such consent, as the case may be,

8.3   Execution of Supplemental Guarantees

        In executing, or accepting the additional trusts created by, any supplemental indenture permitted by this Article or the modifications thereby of the trusts created by this Guarantee, the Security Trustee shall be entitled to receive, and shall be fully protected in acting and relying upon, an Opinion of Counsel stating that the execution of such supplemental indenture is authorized or permitted by this Guarantee. The Security Trustee may, but shall not be obligated to, enter into any such supplemental indenture which affects the Security Trustee's own rights, duties or immunities under this Guarantee or otherwise.

8.4   Effect of Supplemental Indentures

        Upon the execution of any supplemental indenture under this Article, this Guarantee shall be modified in accordance therewith, and such supplemental indenture shall form a part of this Guarantee for all purposes.

8.5   Notice of Supplemental Guarantees

        Promptly after the execution by the Guarantor and the Security Trustee of any supplemental indenture pursuant to the provisions of Section 8.2, the Guarantor shall give notice thereof to the Holders of each of the outstanding Series 3 Shares affected, in the manner provided for in Section 1.6, setting forth in general terms the substance of such supplemental indenture.


ARTICLE 9
COVENANTS

9.1   Existence

        Subject to Article 7 the Guarantor will do or cause to be done all things necessary to preserve and keep in full force and effect its existence and the rights and franchises of the Guarantor and its subsidiaries; provided, however, that the Guarantor shall not be required to preserve any such right or franchise if the Guarantor shall determine that the preservation thereof is no longer desirable in the conduct of the business of the Guarantor.

9.2   Security Trustee Not Required to Verify Liquidation Amount

        The Guarantor will not require the Security Trustee to calculate or verify the Liquidation Amount. When requested by the Security Trustee, the Liquidation Amount shall be specified in an Officer's Certificate and delivered to the Security Trustee.

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9.3   Restriction on Dividends

        The Guarantor hereby covenants and agrees that if and for so long as either the board of directors of the Corporation has failed to declare, or the Corporation has failed to pay, dividends on the Series 3 Shares, in each case, in accordance with the share conditions attaching thereto, then the Guarantor shall not declare or pay any dividends on its shares or make any distributions or pay any dividends on securities of any successor entity of the Guarantor.


ARTICLE 10
PURCHASE OF SERIES 3 SHARES

10.1 Purchase of Series 3 Shares

        Subject to applicable law, at any time when the Guarantor is not in default hereunder, the Guarantor may purchase Series 3 Shares at any price in the market (including purchases from or through an investment dealer or a firm holding membership on a recognized stock exchange) or by tender available to all Holders of Series 3 Shares or by private contract, in each case in accordance with the terms of the Series 3 Shares.


ARTICLE 11
MEETINGS OF HOLDERS OF SERIES 3 SHARES

11.1 Purposes for Which Meetings May Be Called

        A meeting of the Holders of the Series 3 Shares may be called at any time and from time to time pursuant to the provisions of this Article for one or more of the following purposes:

11.2 Call, Notice and Place of Meetings

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11.3 Persons Entitled to Vote at Meetings

        To be entitled to vote at any meeting of Holders of Series 3 Shares, a Person shall be (1) a Holder of one or more outstanding Series 3 Shares, or (2) a Person appointed by an instrument in writing as proxy for a Holder or Holders of one or more outstanding Series 3 Shares by such Holder of Holders. The only Persons who shall be entitled to be present or to speak at any meeting of Holders of Series 3 Shares shall be the Persons entitled to vote at such meeting and their respective counsel, any representatives of the Security Trustee and its counsel, and any representatives of the Guarantor and its counsel.

11.4 Quorum; Action

        The Holders representing not less than 25% of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares shall constitute a quorum for a meeting of Holders of Series 3 Shares; provided, however, that, if any action is to be taken at such meeting with respect to a consent or waiver which this Guarantee expressly provides may be given by the Holders of not less than a specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares, the Persons entitled to vote such specified percentage in aggregate amount of the outstanding Series 3 Shares shall constitute a quorum. In the absence of a quorum within 30 minutes of the time appointed for any such meeting, the meeting shall, if convened at the request of Holders of Series 3 Shares, be dissolved. In any other case the meeting may be adjourned for a period of not less than 10 days as determined by the chairman of the meeting prior to the adjournment of such meeting. In the absence of a quorum at any such adjourned meeting, such adjourned meeting may be further adjourned for a period of not less than 10 days as determined by the chairman of the meeting prior to the adjournment of such adjourned meeting. Notice of the reconvening of any adjourned meeting shall be given as provided in Section 11.2(a), except that such notice need be given only once not less than five days prior to the date on which the meeting is scheduled to be reconvened.

        Subject to the foregoing, at the reconvening of any meeting adjourned for lack of a quorum, the Holders of Series 3 Shares entitled to vote at such meeting present in person or by proxy shall constitute a quorum for the taking of any action set forth in the notice of the original meeting.

        Except as limited by the proviso to Section 8.2, any resolution presented to a meeting or adjourned meeting duly reconvened at which a quorum is present as aforesaid may be adopted by the affirmative vote of the Holders representing not less than a majority of the aggregate Liquidation Amount of Series 3 Shares represented at such meeting in person or by proxy; provided, however, that, except as limited by the proviso to Section 8.2, any resolution with respect to any request, demand, authorization, direction, notice, consent, waiver or other action which this Guarantee expressly provides may be made, given or taken by the Holders of a specified percentage, which is less than a majority of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares may be adopted at a meeting or an adjourned meeting duly reconvened and at which a quorum is present as aforesaid by the affirmative vote of the Holders of not less than such specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares.

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        Any resolution passed or decision taken at any meeting of Holders of Series 3 Shares duly held in accordance with this Section shall be binding on all the Holders of Series 3 Shares, whether or not present or represented at the meeting.

        Notwithstanding the foregoing provisions of this Section 11.4, if any action is to be taken at a meeting of Holders of Series 3 Shares with respect to any request, demand, authorization, direction, notice, consent, waiver or other action that this Guarantee expressly provides may be made, given or taken by the Holders of a specified percentage of the aggregate Liquidation Amount of all of the then outstanding Series 3 Shares affected thereby:

11.5 Determination of Voting Rights; Conduct and Adjournment of Meetings

11.6 Counting Votes and Recording Action of Meetings

        The vote upon any resolution submitted to any meeting of Holders of Series 3 Shares shall be by written ballot(s) on which shall be subscribed the signatures of the Holders of Series 3 Shares or of their representatives by proxy and the number of outstanding Series 3 Shares held or represented by them. The permanent chairman of the meeting shall appoint two inspectors of votes who shall count all votes cast at the meeting for or against any resolution and who shall make and file with the secretary of the meeting their verified written reports in duplicate of all votes cast at the meeting. A record, at

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least in duplicate, of the proceedings of each meeting of Holders of Series 3 Shares shall be prepared by the Secretary of the meeting and there shall be attached to said record the original reports of the inspectors of votes on any vote by ballot taken thereat and affidavits by one or more persons having knowledge of the facts setting forth a copy of the notice of the meeting and showing that said notice was given as provided in Section 11.2 and, if applicable, Section 11.4. Each copy shall be signed and verified by the affidavits of the permanent chairman and secretary of the meeting and one such copy shall be delivered to the Guarantor, and another to the Security Trustee to be preserved by the Security Trustee, the latter to have attached thereto the ballots voted at the meeting. Any record so signed and verified shall be conclusive evidence of the matters therein stated.

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        This Guarantee may be executed in any number of counterparts, each of which so executed shall be deemed to be an original, but all such counterparts shall together constitute but one and the same Guarantee.

        IN WITNESS WHEREOF the parties hereto have duly executed and delivered this Guarantee as of the date first written above.

    CPI PREFERRED EQUITY LTD.

 

 

Per:

 

  

        Name:    
        Title:    

 

 

Per:

 

 

        Name:    
        Title:    

 

 

ATLANTIC POWER CORPORATION

 

 

Per:

 

 

        Name:    
        Title:    

 

 

Per:

 

  

        Name:    
        Title:    

 

 

COMPUTERSHARE TRUST COMPANY OF CANADA

 

 

Per:

 

  

        Name:    
        Title:    

 

 

Per:

 

 

        Name:    
        Title:    

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SCHEDULE A

        The Security Trustee shall invest the funds in Authorized Investments in its name in accordance with a direction from the Guarantor. Any direction from the Guarantor to the Security Trustee shall be in writing and shall be provided to the Security Trustee no later than 9:00 a.m. (Calgary time) on the day on which the investment is to be made. Any such direction received by the Security Trustee after 9:00 a.m. (Calgary time) or received on a Saturday, a Sunday or any other day that is a statutory or civic holiday in the cities of Calgary or Toronto shall be deemed to have been given prior to 9:00 a.m. (Calgary time) on the next day that is not a Saturday, a Sunday or any other day that is a statutory or civic holiday in the cities of Calgary or Toronto. For the purpose hereof, "Authorized Investments" means short term interest bearing or discount debt obligations issued or guaranteed by the Government of Canada or a Province of Canada or a Canadian chartered bank provided that such obligation is rated at least R1 (middle) by DBRS Inc. or an equivalent rating service.

Note:    Authorized Investments that are not short term interest bearing or discount debt obligations issued or guaranteed by the Government of Canada or a Province will be sold, if applicable or held to maturity one business day before the release of cash balances. Cash balances will be held in the Security Trustee's deposit department, the deposit department of one of its Affiliates or the deposit department of a Canadian chartered bank at a rate of interest determined at the time of deposit. For the purpose of this Schedule A, "Affiliate" means affiliated companies within the meaning of the Business Corporations Act (Ontario).

        In the event that the Security Trustee does not receive a direction, or only receives a partial direction, subject to Section 5.8(b) the Security Trustee may hold cash balances and may, but need not, invest same in its deposit department, or the deposit department of a Canadian chartered bank; but the Security Trustee, or a Canadian chartered bank shall not be liable to account for any profit to any parties to this Agreement or to any other person or entity in excess of the interest rate from time to time of the account for deposits pursuant to Section 5.8.

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Annex B
Opinion of TD Securities Inc.


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    GRAPHIC

 

 

TD Securities Inc.
TD Tower
66 Wellington Street West, 9th Floor
Toronto, Ontario M5K 1A2

June 19, 2011

The Board of Directors
Atlantic Power Corporation
200 Clarendon Street, 25th Floor
Boston, MA
02116

To the Board of Directors:

        TD Securities Inc. ("TD Securities") understands that Atlantic Power Corporation ("Atlantic"), intends to enter into an Arrangement Agreement (the "Arrangement Agreement") with Capital Power Income L.P. ("CPILP"), CPI Income Services Ltd., and CPI Investments Inc. (the "Corporation"), to acquire, directly and indirectly, all of the outstanding partnership units ("Units") of CPILP, (the "Proposed Transaction" or "Transaction") for consideration of $19.40 per Unit. Atlantic will indirectly acquire approximately 29% of the Units through its acquisition of all of the outstanding shares of the Corporation. A sale of the CPILP assets located in North Carolina to an indirect subsidiary of Capital Power L.P. will be completed in connection with the Transaction. The Transaction will be implemented by way of a plan of arrangement under section 192 of the Canada Business Corporations Act pursuant to which CPILP unitholders will have the option to elect, for each Unit sold, to receive either (i) 1.3 common shares of Atlantic, or (ii) $19.40 in cash, subject to certain proration procedures as more fully set forth in the Arrangement Agreement (the "Consideration"). The price payable for the shares of the Corporation pursuant to the Transaction is effectively the same as the Consideration in respect of the Units held by the Corporation, a portion of which will be satisfied with cash distributed to Atlantic from the proceeds of the sale of CPILP's North Carolina assets.

        TD Securities understands that CPILP will arrange a meeting of its unitholders to seek approval of at least 662/3% of the votes cast on an arrangement resolution by CPILP unitholders and of at least a majority of the votes cast excluding the Units owned by Capital Power Corporation ("CPX") and parties related to CPX. TD Securities has been advised that CPX, which is CPILP's largest unitholder, and the shareholders of the Corporation have each agreed to support the Transaction and to cause the Corporation to vote its Units (representing approximately 29% of the total Units outstanding) in support of the arrangement resolution. TD Securities also understands that Atlantic will arrange a meeting of Atlantic shareholders to seek the approval of at least a majority of votes cast on a resolution authorizing the issuance by Atlantic of that number of Atlantic common shares required to complete the Proposed Transaction. The above description is summary in nature. The specific terms of the Proposed Transaction will be set out in the Arrangement Agreement.


ENGAGEMENT OF TD SECURITIES

        TD Securities was engaged by Atlantic Power Holdings Inc. pursuant to an engagement agreement dated as of October 20, 2010 (the "Engagement Agreement") to provide, among other things, financial advisory services to Atlantic Power Holdings Inc. and/or any of its subsidiary, parent or affiliated companies (collectively, "Atlantic Power Holdings"). These financial advisory services included, among other things, the preparation and delivery to the Board of Directors of Atlantic (the "Board") of TD Securities' opinion (the "Fairness Opinion") as to the fairness to Atlantic, from a financial point of

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view, of the Consideration to be paid by Atlantic in connection with the Proposed Transaction. TD Securities has not prepared a valuation of CPILP or any of its respective securities or assets or liabilities nor has TD Securities prepared a valuation of Atlantic or any of its respective securities or assets or liabilities and the Fairness Opinion should not be construed as such.

        The terms of the Engagement Agreement provide that TD Securities will receive a fee for its services, a portion of which is payable upon public announcement of the Proposed Transaction and upon delivery of the Fairness Opinion and a significant portion of which is contingent upon completion of the Proposed Transaction or in the event Atlantic receives a termination fee, and is to be reimbursed for its reasonable out-of-pocket expenses. In addition, Atlantic Power Holdings Inc. has agreed to indemnify TD Securities, in certain circumstances, against certain expenses, losses, claims, actions, suits, proceedings, damages and liabilities incurred in connection with the provision of its services.

        The Fairness Opinion is being provided to the Board pursuant to the terms of the Engagement Agreement. The Fairness Opinion is intended solely for the use of the Board with respect to the Proposed Transaction, and the Fairness Opinion (including the fact that it has been delivered by TD Securities) must not be published, reproduced, disseminated, quoted from, made public or referred to, in whole or in part, or be used or relied upon by any other person, or for any other purpose, without TD Securities' prior written consent, except that a copy of this opinion may be included in its entirety in the management information circular to be sent to the shareholders of Atlantic in respect of the Transaction and any filing Atlantic is required to make with the Securities and Exchange Commission in connection with the Transaction, if such inclusion is required by applicable law.


CREDENTIALS OF TD SECURITIES

        TD Securities is a Canadian investment banking firm with operations in a broad range of investment banking activities, including corporate and government finance, mergers and acquisitions, equity and fixed income sales and trading, investment management and investment research. TD Securities has participated in a significant number of transactions involving public and private companies and has extensive experience in preparing fairness opinions.

        The Fairness Opinion is the opinion of TD Securities and its form and content have been approved by a committee of senior investment banking professionals of TD Securities, each of whom is experienced in the preparation of fairness opinions and merger, acquisition and divestiture matters.


RELATIONSHIP WITH INTERESTED PARTIES

        Neither TD Securities, nor any of its affiliates is an insider, associate or affiliate (as those terms are defined in the Securities Act (Ontario)) of Atlantic, CPILP or any of their respective affiliates (collectively, the "Interested Parties"). Neither TD Securities nor any of its affiliates is an advisor to any Interested Party with respect to the Proposed Transaction, other than to Atlantic Power Holdings pursuant to the Engagement Agreement.

        TD Securities and its affiliates have not been engaged to provide any financial advisory services, have not acted as lead or co-lead manager on any offering of securities of Atlantic or any other Interested Party, or had a material financial interest in any transaction involving Atlantic or any other Interested Party during the 24 months preceding the date on which TD Securities was first contacted in respect of the Proposed Transaction other than services provided under the Engagement Letter or as described hereinafter. TD Securities acted as a co-manager for the offering of Atlantic common shares and convertible debentures in October 2010. TD Securities acted as co-financial advisor, co-lead underwriter, lead arranger and co-lead arranger in connection with the initial public offering of common shares of CPX and the related reorganization and acquisition transactions involving EPCOR Utilities Inc. ("EPCOR") and Capital Power LP and related financings in 2009. TD Securities acted as

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financial advisor to EPCOR for two unrelated transactions during the 24 month period referenced above.

        No understanding or agreement exists between TD Securities and any Interested Party with respect to future financial advisory or investment banking business other than those that may arise as a result of the terms of the Engagement Agreement. TD Securities may in the future, in the ordinary course of its business, perform financial advisory or investment banking services for Atlantic, any other Interested Party or any of their respective associates. A Canadian chartered bank, the parent company of TD Securities, directly or through one or more affiliates may provide banking services, extend loans or credit, offer financial products or provide other financial services to Atlantic, any other Interested Party or any of its associates.

        TD Securities and its affiliates act as a trader and dealer, both as principal and as agent, in major financial markets and, as such, may have and may in the future have positions in the securities of Atlantic and/or any other Interested Party and/or their respective associates and, from time to time, may have executed or may execute transactions on behalf of Atlantic and/or any other Interested Party and/or their respective associates or other clients for which it may have received or may receive compensation. As an investment dealer, TD Securities conducts research on securities and may, in the ordinary course of its business, provide research reports and investment advice to its clients on investment matters, including matters with respect to the Proposed Transaction, Atlantic and/or any other Interested Party and/or their respective associates.


SCOPE OF REVIEW

        In connection with the Fairness Opinion, TD Securities reviewed (where applicable) and relied upon (without attempting to verify independently the completeness, accuracy, or fair presentation of) or carried out, among other things, the following:

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        TD Securities has, to the best of its knowledge, been provided access by Atlantic or CPILP to all information requested by TD Securities.


PRIOR VALUATIONS

        Atlantic has represented to TD Securities that there have not been any prior valuations or appraisals relating to Atlantic or CPILP or any of their respective affiliates or any of their respective material assets or liabilities made in the preceding 24 months and in the possession or control of Atlantic other than those which have been provided to TD Securities or, in the case of valuations known to Atlantic which it does not have within its possession or control, notice of which has not been given to TD Securities.


ASSUMPTIONS AND LIMITATIONS

        With Atlantic's acknowledgement and agreement, TD Securities has relied upon and assumed the accuracy, completeness and fair presentation of all data, documents, advice, opinions and other information obtained by it from public sources (including on the System for Electronic Document Analysis and Retrieval ("SEDAR")) or provided to it by or on behalf of Atlantic and/or CPILP and/or their respective personnel, consultants and advisors, or otherwise obtained by TD Securities, including the Certificate and all other documents and information referred to above (collectively, the "Data"). The Fairness Opinion is premised and conditional upon such accuracy, completeness and fair presentation and upon there being no "misrepresentation" (as defined in the Securities Act (Ontario)) in the Data. In addition, TD Securities has assumed that there is no information relating to the business, operations, assets, liabilities, condition (financial or otherwise), capital or prospects of Atlantic, CPILP or any of their respective affiliates that is or could reasonably be expected to be

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material to the Fairness Opinion that has not been disclosed or otherwise made available to TD Securities as part of the Data. Subject to the exercise of professional judgment and except as expressly described herein, TD Securities has not attempted to verify independently the accuracy, completeness or fair presentation of any of the Data.

        With respect to the budgets, forecasts, projections or estimates provided to TD Securities and used in its analyses, TD Securities notes that projecting future results is inherently subject to uncertainty. TD Securities has assumed, however, that such budgets, forecasts, projections and estimates were prepared using the assumptions identified therein (as discussed between senior management of Atlantic and TD Securities) which TD Securities has been advised are (or were at the time of preparation and continue to be), in the opinion of Atlantic, reasonable in the circumstances. In addition, TD Securities has assumed that the expected synergies will be achieved at the times and in the amounts projected by Atlantic. TD Securities expresses no independent view as to the reasonableness of such budgets, forecasts, projections and estimates and the assumptions on which they are based.

        TD Securities was not engaged to review and has not reviewed any of the legal, accounting or tax aspects of the Proposed Transaction. In preparing the Fairness Opinion, TD Securities has assumed that the Proposed Transaction complies with all applicable laws and accounting requirements and has no adverse tax or other adverse consequences for Atlantic.

        A senior officer of Atlantic has represented to TD Securities in the Certificate, among other things, that to the best of his knowledge, information and belief after due inquiry (i) Atlantic has no information or knowledge of any facts public or otherwise not specifically provided to TD Securities relating to Atlantic or CPILP which would reasonably be expected to affect materially the Opinion to be given by TD Securities; (ii) with the exception of forecasts, projections or estimates referred to in subparagraph (iv) below, the information, data and other material (collectively, the "Information") as filed under Atlantic's profile on SEDAR and/or provided to TD Securities by or on behalf of Atlantic or its representatives in respect of Atlantic and its affiliates in connection with the Proposed Transaction is or, in the case of historical Information was, at the date of preparation, true, complete and accurate and did not and does not contain any untrue statement of a material fact and does not omit to state a material fact necessary to make the Information not misleading in the light of circumstances in which it was presented; (iii) to the extent that any of the Information identified in subparagraph (ii) above is historical, there have been no changes in any material facts or new material facts since the respective dates thereof which have not been disclosed to TD Securities or updated by more current information not provided to TD Securities by Atlantic and there has been no material change, financial or otherwise in the financial condition, assets, liabilities (contingent or otherwise), business, operations or prospects of Atlantic and no material change has occurred in the Information or any part thereof which would have or which would reasonably be expected to have a material effect on the Opinion; (iv) any portions of the Information provided to TD Securities (or filed on SEDAR) which constitute forecasts, projections or estimates were prepared using the assumptions identified therein, which, in the reasonable opinion of Atlantic, are (or were at the time of preparation and continue to be) reasonable in the circumstances; (v) there have been no valuations or appraisals relating to Atlantic or CPILP or any of their respective affiliates or any of their respective material assets or material liabilities made in the preceding 24 months and in the possession or control of Atlantic other than those which have been provided to TD Securities or, in the case of valuations known to Atlantic which it does not have within its possession or control, notice of which has not been given to TD Securities; (vi) there have been no verbal or written offers or serious negotiations for or transactions involving any material property of Atlantic or any of its affiliates during the preceding 24 months which have not been disclosed to TD Securities; (vii) since the dates on which the Information was provided to TD Securities (or filed on SEDAR), no material transaction has been entered into by Atlantic or any of its affiliates except as publicly disclosed by Atlantic or otherwise disclosed to TD Securities; (viii) other than as disclosed in the Information, neither Atlantic nor any of

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its affiliates has any material contingent liabilities and there are no actions, suits, claims, proceedings, investigations or inquiries pending or threatened against or affecting the Proposed Transaction, Atlantic or any of its affiliates at law or in equity or before or by any federal, national, provincial, state, municipal or other governmental department, commission, bureau, board, agency or instrumentality which may, in any way, materially adversely affect Atlantic or its affiliates or the Proposed Transaction; (ix) all financial material, documentation and other data concerning the Proposed Transaction, Atlantic and its affiliates, including any projections or forecasts provided to TD Securities, were prepared on a basis consistent in all material respects with the accounting policies applied in the most recent audited consolidated financial statements or unaudited consolidated interim financial statements of Atlantic; (x) there are no agreements, undertakings, commitments or understanding (whether written or oral, formal or informal) relating to the Proposed Transaction, except as have been disclosed to TD Securities; (xi) the contents of any and all documents prepared in connection with the Transaction for filing with regulatory authorities or delivery or communication to securityholders of Atlantic (collectively, the "Disclosure Documents") have been, are and will be true, complete and correct in all material respects and have not and will not contain any misrepresentation (as defined in the Securities Act (Ontario)) and the Disclosure Documents have complied, comply and will comply with all requirements under applicable laws; (xii) Atlantic has complied in all material respects with the Engagement Agreement; and (xiii) to the best of its knowledge, information and belief after due inquiry, there is no plan or proposal for any material change (as defined in the Securities Act (Ontario)) in the affairs of Atlantic which has not been disclosed to TD Securities. For the purposes of subparagraphs (v) and (vi), "material assets", "material liabilities" and "material property" shall include assets, liabilities and property of Atlantic or its affiliates having a gross value greater than or equal to $20 million

        In preparing the Fairness Opinion, TD Securities has made several assumptions, including that all final executed versions of agreements and documents relating to the Proposed Transaction will conform in all material respects to the drafts provided to or terms discussed with TD Securities, all conditions to the completion of the Proposed Transaction can and will be satisfied in due course, that all consents, permissions, exemptions or orders of relevant regulatory authorities or third parties will be obtained, without adverse condition or qualification, and that the actions being taken and procedures being followed to implement the Proposed Transaction are valid and effective and comply with all applicable laws and regulatory requirements. In its analysis in connection with the preparation of the Fairness Opinion, TD Securities made numerous assumptions with respect to industry performance, general business and economic conditions, and other matters, many of which are beyond the control of TD Securities, Atlantic, CPILP or their respective affiliates. Among other things, TD Securities has assumed the accuracy, completeness and fair presentation of and has relied upon the financial statements forming part of the Data. The Fairness Opinion is conditional on all such assumptions being correct.

        The Fairness Opinion has been provided for the exclusive use of the Board and is not intended to and does not constitute a recommendation to the Board. Furthermore, the Fairness Opinion is not intended to be, and does not constitute, a recommendation that Atlantic shareholders vote in favour of the Proposed Transaction or as an opinion concerning the trading price or value of any securities of Atlantic following the announcement or completion of the Proposed Transaction. The Fairness Opinion does not address the relative merits of the Proposed Transaction as compared to other transactions or business strategies that might be available to Atlantic, nor does it address the underlying business decision to implement the Proposed Transaction. In preparing the Fairness Opinion TD Securities did not consider the economic or other interests of either individual, or particular groups of, Atlantic stakeholders. The Fairness Opinion must not be used by any other person or relied upon by any other person other than the Board without the express prior written consent of TD Securities. The Fairness Opinion is rendered as of June 19, 2011, on the basis of securities markets, economic and general business and financial conditions prevailing on that date and the condition and prospects, financial and

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otherwise, of Atlantic and CPILP and their respective subsidiaries and affiliates as they were reflected in the Data provided or otherwise available to TD Securities. Although TD Securities reserves the right to change, modify, update, supplement or withdraw the Fairness Opinion in the event that there is any material change in any fact or matter affecting the Fairness Opinion, it disclaims any undertaking or obligation to advise any person of any such material change that may come to its attention or to change, modify, update, supplement or withdraw the Fairness Opinion as a result of any such material change. TD Securities has not undertaken an independent evaluation, appraisal or physical inspection of any assets or liabilities of Atlantic or CPILP or their respective subsidiaries. TD Securities is not an expert on, and did not render advice to the Board regarding, legal, accounting, regulatory or tax matters. The Fairness Opinion (including the fact that it has been delivered by TD Securities) is not to be reproduced, disseminated, quoted from, made public or referred to (in whole or in part) without TD Securities' prior written consent, except that a copy of this opinion may be included in its entirety in the management information circular to be sent to the shareholders of Atlantic in respect of the Transaction and any filing Atlantic is required to make with the Securities and Exchange Commission in connection with the Transaction, if such inclusion is required by applicable law.

        TD Securities' conclusion as to the fairness, from a financial point of view, of the Consideration to be paid by Atlantic in connection with the Proposed Transaction is based on its review of the Proposed Transaction taken as a whole, rather than on any particular element of the Proposed Transaction, and this Fairness Opinion should be read in its entirety.

        The preparation of a fairness opinion is a complex process and is not necessarily amenable to partial analysis or summary description. TD Securities believes that its analyses must be considered as a whole and that selecting portions of the analyses or the factors considered by it, without considering all factors and analyses together, could create an incomplete or misleading view of the process underlying the Fairness Opinion.


FAIRNESS CONCLUSION

        Based upon and subject to the foregoing, TD Securities is of the opinion that, as of June 19, 2011, the Consideration to be paid by Atlantic in connection with the Proposed Transaction is fair, from a financial point of view, to Atlantic.

Yours very truly,

GRAPHIC

TD Securities Inc.

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Annex C
Opinion of Morgan Stanley & Co. LLC


Table of Contents

June 19, 2011

Board of Directors
Atlantic Power Corporation
200 Clarendon Street
Floor 25
Boston, MA 02116

Members of the Board:

        We understand that Capital Power Income L.P. (the "Partnership"), CPI Income Services Ltd. ("GP"), CPI Investments Inc. ("Corporation") and Atlantic Power Corporation (the "Buyer") propose to enter into an Arrangement Agreement, substantially in the form of the draft dated June 19, 2011 (the "Arrangement Agreement"), which provides, among other things, for the acquisition by the Buyer of all of the outstanding limited partnership units of the Partnership (the "Partnership Units"), and all of the outstanding Class A Shares in the capital of the Corporation (the "Class A Corporation Shares") and Class B Shares in the capital of the Corporation (the "Class B Corporation Shares" and, together with the Class A Corporation Shares, the "Corporation Shares"), pursuant to a plan of arrangement (the "Plan of Arrangement"), whereby (i) each Partnership Unit, other than any Partnership Units held by the Buyer, GP and the Corporation, will be exchanged for, at the election of the holder of such Partnership Unit (each, a "Partnership Unitholder") (a) 1.3 common shares in the capital of the Buyer (the "Buyer Shares") or (b) C$19.40 in cash (collectively, the "Partnership Consideration") subject to certain proration procedures to be more fully set forth in the Plan of Arrangement, (ii) all Class A Corporation Shares will be exchanged for C$1.00 (the "Class A Corporation Share Consideration") and (iii) all Class B Corporation Shares will be exchanged for (a) a promissory note to be issued by the Buyer in the principal amount of C$121,405,211 (the "Purchaser Note") (which note will subsequently be repaid and cancelled pursuant to the Plan of Arrangement) and (b) at the election of Capital Power, L.P., the holder of such Class B Corporation Shares ("CPLP"), and subject to certain proration procedures to be more fully set forth in the Plan of Arrangement, either (x) a number of Buyer Shares equal to (A) the product of (aa) 1.3 and (bb) the sum of the number of Partnership Units held by the Corporation and the number of units of the Partnership held by GP, less (B) the product of (aa) the principal amount of the Purchaser Note divided by C$19.40 and (bb) 1.3 or (y) cash equal to (A) the product of (aa) C$19.40 and (bb) the sum of the number of Partnership Units held by the Corporation and the number of units of the partnership held by GP, less (B) the principal amount of the Purchaser Note (the "Class B Corporation Share Consideration" and, together with the Partnership Consideration and the Class A Corporation Share Consideration, the "Consideration"). We further understand that in connection with the transactions contemplated by the Plan of Arrangement, CPI USA Holdings LLC, CPI Power Holdings Inc. (each an indirect subsidiary of the Partnership) and Capital Power (US Holdings) Inc. ("Power USA") (an indirect subsidiary of CPLP), will enter into a purchase agreement (the "NC Purchase Agreement") pursuant to which Power USA will indirectly acquire all of the equity interests in CPI USA North Carolina LLC for consideration consisting of cash in the amount of C$121,405,211, which will then be used to indirectly acquire 6,258,000.57 Partnership Units held by CPLP through the Corporation (the "NC Proceeds" and such transaction, the "North Carolina Transaction"). Pursuant to the Plan of Arrangement, and a distribution agreement to be entered into in connection with the Plan of Arrangement by the Buyer, the Partnership and a number of direct and indirect subsidiaries of the Partnership, the NC Proceeds will ultimately be transferred to the Partnership and used in part to repay the Partnership's senior credit facilities, and the balance will be transferred to the Buyer. The Buyer will use that portion of the NC Proceeds, along with other cash, to fully pay and satisfy the Purchaser Note, which will subsequently be cancelled. The Plan of Arrangement and all of the related transactions contemplated by the Arrangement Agreement are referred to herein as the "Transaction," and the terms and conditions of the Transaction are more fully set forth in the Arrangement Agreement and the related agreements referenced therein.

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        You have asked for our opinion as to whether the Consideration to be paid by the Buyer pursuant to the Arrangement Agreement is fair from a financial point of view to the Buyer.

        For purposes of the opinion set forth herein, we have:

        We have assumed and relied upon, without independent verification, the accuracy and completeness of the information that was publicly available or supplied or otherwise made available to us by the Partnership and the Buyer, and formed a substantial basis for this opinion. With respect to the Partnership Forecasts, we have assumed that they have been reasonably prepared on bases reflecting the best currently available estimates and judgments of the management of the Partnership of the future financial performance of the Partnership. With respect to the Buyer -Partnership Forecasts, the Buyer Forecasts, and the Synergy/Cost Savings, we have assumed that they have been reasonably prepared on bases reflecting the best currently available estimates and judgments of the management of the Buyer of the future financial performance of the Partnership and the Buyer and the other matters covered thereby, and based on the assessments of the management of the Buyer as to the relative likelihood of achieving the future financial results reflected in the Partnership Forecasts and the Buyer-Partnership Forecasts, we have relied, at the direction of the Buyer, on the Buyer-Partnership Forecasts

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for purposes of our opinion. In addition, we have assumed that the Synergies/Cost Savings will be achieved at the times and in the amounts projected. In rendering this opinion, we have assumed that the final form of the Arrangement Agreement will not differ in any material respect from the draft reviewed by us. In addition, we have assumed that the Transaction will be consummated in accordance with the terms set forth in the Arrangement Agreement without any waiver, amendment or delay of any terms or conditions. Morgan Stanley has assumed that in connection with the receipt of all the necessary governmental, regulatory or other approvals and consents required for the proposed Transaction, no delays, limitations, conditions or restrictions will be imposed that would have a material adverse effect on the contemplated benefits expected to be derived in the proposed Transaction. We are not legal, tax or regulatory advisors. We are financial advisors only and have relied upon, without independent verification, the assessment of the Buyer and the Partnership and their legal, tax or regulatory advisors with respect to legal, tax or regulatory matters. We express no view on, and our opinion does not address, any other term or aspect of the Arrangement Agreement or the Transaction or any term or aspect of any other agreement or instrument contemplated by the Arrangement Agreement or entered into in connection with the Transaction, including, without limitation, the NC Purchase Agreement, or the fairness of the transactions contemplated thereby, including, without limitation, the North Carolina Transaction. We express no opinion as to the relative fairness of any portion of the Consideration to be paid by the Buyer for the Partnership Units and the Corporation Shares. We express no opinion with respect to the fairness of the amount or nature of the compensation to any of the officers, directors or employees of the Partnership or the Corporation, or any class of such persons, relative to the consideration to be paid to the holders of the Partnership Units and the Corporation Shares in the Transaction. We have not made any independent valuation or appraisal of the assets or liabilities of the Partnership, the Corporation or the Buyer, nor have we been furnished with any such valuations or appraisals. Our opinion is necessarily based on financial, economic, market and other conditions as in effect on, and the information made available to us as of, the date hereof. Events occurring after the date hereof may affect this opinion and the assumptions used in preparing it, and we do not assume any obligation to update, revise or reaffirm this opinion.

        We have acted as financial advisor to the Board of Directors of the Buyer in connection with the Transaction and will receive a fee for our services, a substantial portion of which is contingent upon the closing of the Transaction. In addition, Morgan Stanley or one or more of its affiliates may provide to the Buyer a portion of the financing required in connection with the Transaction, for which Morgan Stanley would receive additional fees from the Buyer. Morgan Stanley may also seek to provide financial advisory and financing services to the Buyer in the future and expects to receive fees for the rendering of these services.

        Please note that Morgan Stanley is a global financial services firm engaged in the securities, investment management and individual wealth management businesses. Our securities business is engaged in securities underwriting, trading and brokerage activities, foreign exchange, commodities and derivatives trading, prime brokerage, as well as providing investment banking, financing and financial advisory services. Morgan Stanley, its affiliates, directors and officers may at any time invest on a principal basis or manage funds that invest, hold long or short positions, finance positions, and may trade or otherwise structure and effect transactions, for their own account or the accounts of their customers, in debt or equity securities or loans of the Buyer, the Partnership, or any other company, or any currency or commodity, that may be involved in the Transaction, or any related derivative instrument.

        This opinion has been approved by a committee of Morgan Stanley investment banking and other professionals in accordance with our customary practice. This opinion is for the information of the Board of Directors of the Buyer (in its capacity as such) and may not be used for any other purpose without our prior written consent, except that a copy of this opinion may be included in its entirety in the management information circular to be sent to the shareholders of the Buyer in respect of the

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Transaction and any filing the Buyer is required to make with the Securities and Exchange Commission in connection with the Transaction if such inclusion is required by applicable law. In addition, this opinion does not in any manner address the prices at which the Buyer Shares will trade following consummation of the Transaction or at any time and Morgan Stanley expresses no opinion or recommendation as to how the shareholders of the Buyer and the Partnership Unitholders should vote at the security-holders' meetings to be held in connection with the Transaction.

        Based on and subject to the foregoing, we are of the opinion on the date hereof that the Consideration to be paid by the Buyer pursuant to the Arrangement Agreement is fair from a financial point of view to the Buyer.

 

    Very truly yours,

 

 

MORGAN STANLEY & CO. LLC

 

 

By:

 

/s/ DAVID WHITCHER

David Whitcher
Executive Director

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Annex D
Opinion of CIBC World Markets Inc.


Table of Contents

LOGO

June 19, 2011

The Board of Directors of CPI Income Services Ltd., the general partner of
Capital Power Income L.P.
10065 Jasper Avenue
Edmonton, Alberta T5J 3B1

To the Board of Directors:

        CIBC World Markets Inc. ("CIBC", "we" or "us") understands that Capital Power Income L.P. ("CPILP" or the "Company"), its general partner, CPI Income Services Ltd. (the "General Partner") and CPI Investments Inc. ("CPI Investments") are proposing to enter into an arrangement agreement (the "Arrangement Agreement") with Atlantic Power Corporation ("Atlantic" or the "Purchaser") providing for, among other things, the acquisition by the Purchaser of all of the outstanding limited partnership units (the "Units") of the Company (the "Proposed Transaction").

        We understand that pursuant to the Arrangement Agreement:

Engagement of CIBC

        By letter agreement dated November 19, 2010 and effective as of October 1, 2010 (the "Engagement Agreement"), the Company retained CIBC to act as financial advisor to the Company and the board of directors of the General Partner (the "Board of Directors") in connection with the Proposed Transaction and any alternative transaction. Pursuant to the Engagement Agreement, the Company has requested that we prepare and deliver to the Board of Directors our written opinion (the

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"Opinion") as to the fairness, from a financial point of view, of the Consideration to be received by Unitholders other than CPC and its affiliates pursuant to the Arrangement Agreement.

        CIBC will be paid a fee for rendering the Opinion and will be paid an additional fee that is contingent upon the completion of the Proposed Transaction or any alternative transaction. The Company has also agreed to reimburse CIBC for its reasonable out-of-pocket expenses and to indemnify CIBC in respect of certain liabilities that might arise out of our engagement.

Credentials of CIBC

        CIBC is one of Canada's largest investment banking firms with operations in all facets of corporate and government finance, mergers and acquisitions, equity and fixed income sales and trading and investment research. The Opinion expressed herein is the opinion of CIBC and the form and content herein have been approved for release by a committee of its managing directors and internal counsel, each of whom is experienced in merger, acquisition, divestiture and valuation matters.

Scope of Review

        In connection with rendering our Opinion, we have reviewed and relied upon, among other things, the following:

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        In addition, we have participated in discussions with members of the senior management of the General Partner and the Purchaser regarding their respective past and current business operations, financial condition and future prospects. We have also participated in discussions with the respective external legal counsel to the Company, the special committee of the Board of Directors and the Purchaser concerning the Proposed Transaction, the Arrangement Agreement and related matters.

Assumptions and Limitations

        Our Opinion is subject to the assumptions, qualifications and limitations set forth below.

        We have not been asked to prepare and have not prepared a formal valuation or appraisal of any of the assets or securities of the Company, the Purchaser or any of their respective affiliates and our Opinion should not be construed as such.

        With your permission, we have relied upon, and have assumed the completeness, accuracy and fair presentation of all financial and other information, data, advice, opinions and representations obtained by us from public sources, or provided to us by the Company, the Purchaser or their respective affiliates or advisors or otherwise obtained by us pursuant to our engagement, and our Opinion is conditional upon such completeness, accuracy and fair presentation. We have not been requested to or attempted to verify independently the accuracy, completeness or fairness of presentation of any such information, data, advice, opinions and representations. We have not met separately with the independent auditors of the Company or the Purchaser in connection with preparing this Opinion and with your permission, we have assumed the accuracy and fair presentation of, and relied upon, the Company's and the Purchaser's audited financial statements and the reports of the auditors thereon and the Company's and the Purchaser's interim unaudited financial statements.

        With respect to the historical financial data, operating and financial forecasts and budgets provided to us concerning the Company and the Purchaser and relied upon in our financial analyses, we have assumed that they have been reasonably prepared on bases reflecting the most reasonable assumptions, estimates and judgements of management of the Company and the Purchaser, having regard to their respective business, plans, financial condition and prospects.

        We have also assumed that all of the representations and warranties contained in the Arrangement Agreement are correct as of the date hereof and that the Proposed Transaction will be completed substantially in accordance with all of the terms and conditions set forth therein and all applicable laws and that the Circular will disclose all material facts relating to the Proposed Transaction and will satisfy all applicable legal requirements.

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        The Company has represented to us, in a certificate of two senior officers of the General Partner dated the date hereof, among other things, that the information, data and other material (financial or otherwise) provided to us by or on behalf of the Company and, to the best of their knowledge, the Purchaser, including the written information and discussions concerning the Company and the Purchaser referred to above under the heading "Scope of Review" (collectively, the "Information"), are complete and correct in all material respects at the date the Information was provided to us and that, since the date on which the Information was provided to us, there has been no material change, financial or otherwise, in the financial condition, assets, liabilities (contingent or otherwise), business, operations or prospects of the Company or any of its affiliates, or, to the best of their knowledge, the Purchaser, and no material change has occurred in the Information or any part thereof which would have or which would reasonably be expected to have a material effect on the Opinion.

        We are not legal, tax or accounting experts and we express no opinion concerning any legal, tax or accounting matters concerning the Proposed Transaction or the sufficiency of this letter for your purposes.

        Our Opinion is rendered on the basis of securities markets, economic and general business and financial conditions prevailing as at the date hereof and the conditions and prospects, financial and otherwise, of the Company and the Purchaser as they are reflected in the Information and as they were represented to us in our discussions with management of the Company, the Purchaser and their respective affiliates and advisors. In our analyses and in connection with the preparation of our Opinion, we made numerous assumptions with respect to industry performance, general business, markets and economic conditions and other matters, many of which are beyond the control of any party involved in the Proposed Transaction.

        The Opinion is being provided to the Board of Directors for its exclusive use only in considering the Proposed Transaction and may not be published, disclosed to any other person, relied upon by any other person, or used for any other purpose, without the prior written consent of CIBC. Our Opinion is not intended to be and does not constitute a recommendation to the Board of Directors as to whether they should approve the Arrangement Agreement nor as a recommendation to any Unitholder as to how to vote or act at the Special Meeting or as an opinion concerning the trading price or value of any securities of the Company, the Purchaser or any of their respective affiliates following the announcement or completion of the Proposed Transaction.

        CIBC believes that its financial analyses must be considered as a whole and that selecting portions of its analyses and the factors considered by it, without considering all factors and analyses together, could create a misleading view of the process underlying the Opinion. The preparation of a fairness opinion is complex and is not necessarily susceptible to partial analysis or summary description and any attempt to carry out such could lead to undue emphasis on any particular factor or analysis.

        The Opinion is given as of the date hereof and, although we reserve the right to change or withdraw the Opinion if we learn that any of the information that we relied upon in preparing the Opinion was inaccurate, incomplete or misleading in any material respect, we disclaim any obligation to change or withdraw the Opinion, to advise any person of any change that may come to our attention or to update the Opinion after the date of this Opinion.

Opinion

        Based upon and subject to the foregoing and such other matters as we considered relevant, it is our opinion, as of the date hereof, that the Consideration to be received by Unitholders pursuant to the Arrangement Agreement is fair, from a financial point of view, to Unitholders other than CPC and its affiliates.

Yours very truly,

/S/ CIBC WORLD MARKETS INC.

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Annex E
Opinion of Greenhill & Co. Canada Ltd.


Table of Contents

CONFIDENTIAL

June 19, 2011

The Board of Directors
CPI Income Services Ltd., the general partner of Capital Power Income L.P.
10065 Jasper Avenue
Edmonton, AB T5J 3B1

Members of the Board of Directors:

        We, Greenhill & Co. Canada Ltd. ("Greenhill") understand that Capital Power Income L.P. (the "Company"), CPI Income Services Ltd (the "General Partner"), CPI Investments Inc. (the "Corporation") and Atlantic Power Corporation ("Purchaser") propose to enter into an arrangement agreement (the "Agreement"), which provides, among other things, for the acquisition of the Company by Purchaser by way of plan of arrangement pursuant to section 192 of the Canada Business Corporation Act (the "Arrangement") in which each holder of limited partnership units ("Partnership Units") of the Company (other than Purchaser, the Corporation and the General Partner) shall receive, at its election, for each Partnership Unit, (x) a number of Purchaser Shares equal to 1.3 or (ii) cash in an amount equal to C$19.40 (in each case, subject to proration and adjustment as set out in the Agreement) (the "Consideration"). The terms and conditions of the Arrangement are more fully set forth in the Agreement. Capitalized terms used but not separately defined herein shall have the meanings given to such terms in the Agreement.

        Greenhill also understands that the Arrangement will be more fully described in the Partnership Circular to be mailed to holders of Partnership Units in respect of a special meeting of holders of Partnership Units to be held for the purpose of approving the Arrangement, among other things. The Arrangement will be subject to a number of conditions, which must be satisfied or waived in order for the Arrangement to become effective, as will be more fully described in the Partnership Circular.

        Pursuant to an engagement letter dated October 1, 2010 (the "Engagement Letter"), the Board of Directors of the General Partner retained Greenhill in connection with the Arrangement, to provide financial advisory services and to prepare and deliver to the Board of Directors of the General Partner our opinion as to the fairness of the Consideration to be received by holders of Partnership Units (other than Purchaser, the General Partner and the Corporation), under the Arrangement, from a financial point of view, to such holders (the "Fairness Opinion").

Relationship with interested parties

        Greenhill is not an insider, associate or affiliate as each such term is defined in the Securities Act (Ontario) of the Company, Purchaser, or any of their respective subsidiaries, associates or affiliates (collectively, the "Interested Parties") nor is it a financial advisor to Purchaser or any other person in connection with the Arrangement, except for acting as a financial advisor to the Company and the Board of Directors of the General Partner as described above.

        Greenhill has not acted as a lead or co-lead underwriter with respect to the distribution of securities for any of the Interested Parties.

        We will be paid a fee for our services as financial advisor to the Company and the Board of Directors of the General Partner, a portion of which is contingent on the consummation of the Arrangement. In addition, the Company has agreed to indemnify us for certain liabilities that may arise out of our engagement.

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Credentials of Greenhill

        Greenhill is a subsidiary of Greenhill & Co., Inc. ("Greenhill & Co."), a leading independent investment bank focused on providing financial advice on significant mergers, acquisitions, restructurings, financings and capital raisings to corporations, partnerships, institutions and governments around the world. Greenhill & Co. is an independent firm listed on the New York Stock Exchange which focuses on advisory work. Greenhill has no research, trading, lending, underwriting or related activities. The Fairness Opinion is an opinion of Greenhill and the form and content herein has been reviewed and approved for release by our fairness committee, each member of which is experienced in mergers, acquisitions, divestitures, evaluations and fairness opinion matters.

Scope of Review

        In connection with rendering our Fairness Opinion, we have reviewed and relied upon, or carried out as the case may be, among other things, the following:

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Assumptions and Limitations

        With the approval of the Board of Directors of the General Partner and as provided for in the Engagement Letter, we have relied upon the completeness, accuracy and fair presentation of all financial and other information, data, advice, opinions and representations obtained by us from public sources or information provided to us by the Company and its advisors and Purchaser and its advisors (collectively, the "Information"). The Fairness Opinion is conditional upon such completeness, accuracy and fair presentation of such Information. Subject to the exercise of professional judgment, we have not attempted to independently verify the completeness, accuracy or fair presentation of any of the Information. With respect to the Company Forecasts and the Purchaser Forecasts that have been furnished to us as part of the Information ("Forecasts"), we have assumed that such Forecasts were reasonably prepared on a basis reflecting the best currently available estimates and good faith judgments of the management of the Company and Purchaser, respectively, as to such matters, and, with the approval of the Board of Directors of the General Partner, we have relied upon such Forecasts in arriving at our Fairness Opinion.

        Senior officers of the General Partner have represented to us in a certificate dated as of the date hereof, among other things, that (i) the Information (as defined above) provided orally by, or in the presence of, an officer, employee, advisor or agent of the Company or in writing by the Company or any of its subsidiaries (as such term is defined in the Securities Act (Ontario)) or their respective agents to Greenhill relating to the Company or any of its subsidiaries or the Arrangement for the purpose of preparing the Fairness Opinion was, at the date the Information was provided to us, and is at the date hereof complete, true and correct in all material respects, and did not and does not contain any untrue statement of a material fact in respect of the Company, its subsidiaries, or the Arrangement and did not and does not omit to state a material fact in respect of the Company, its subsidiaries or the Arrangement necessary to make the Information or any statement contained therein not misleading in light of the circumstances under which the Information was made or provided; (ii) since the dates on which the Information (including the Company Forecasts) were provided to us, except as disclosed in writing to us, there has been no material change, financial or otherwise, in the financial condition, assets, liabilities (contingent or otherwise), business, operations, or prospects of the Company or any of its subsidiaries and no material change has occurred in the Information or any part thereof which would have, or which would reasonably be expected to have, a material effect on the Fairness Opinion; (iii) the Company Forecasts were reasonably prepared by management of the Company on the basis of the best current estimates and good faith judgments of the management of the Company as to such matters, and (iv) to the best of the senior officers' knowledge, information and belief after due inquiry, there are no independent appraisals or valuations or material non-independent appraisals or valuations relating to the Company or any of its subsidiaries or any of their respective material assets or liabilities which have been prepared as of a date within the two years preceding the date hereof and which have not been provided to us by the Company.

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        In preparing the Fairness Opinion, we have made several assumptions, including that the Arrangement will be completed on the terms contemplated in the draft Agreement provided to us, that all of the conditions set out in the Agreement (including the completion of the transactions contemplated by the Partnership Reorganization Agreements in accordance with their terms) will be satisfied, that all of the representations and warranties to be contained in the Agreement are correct as of the date hereof and that the disclosure provided or incorporated by reference in the Partnership Circular to be delivered to the Company's unitholders will be accurate in all material respects.

        This Fairness Opinion is rendered on the basis of securities markets, economic and general business and financial conditions prevailing as at the date hereof and the conditions and prospects, financial and otherwise, of the Company and its subsidiaries and affiliates, as reflected in the information, data and other material (financial or otherwise) reviewed by us and as represented to us in our discussions with the management of the Company. In our analyses and in connection with preparing the Fairness Opinion, we made numerous assumptions with respect to industry performance, general business and economic conditions and other matters, many of which are beyond the control of any party.

        We are not legal, tax or accounting experts and we express no opinion concerning any legal, tax or accounting matters concerning the Arrangement.

        We are not expressing any opinion as to any other aspects of the Arrangement or the related transactions contemplated by the Agreement. In particular, we are not expressing any opinion as to the consideration to be received by EPCOR or CPLP in respect of the Corporation Shares held by them. We express no opinion as to the prices at which the Purchaser Shares will trade at any future time.

        The Fairness Opinion is effective on the date hereof and we disclaim any undertaking or obligation to advise any person of any change in any fact, information or matter affecting the Fairness Opinion that may come or be brought to our attention after the date hereof. Without limiting the foregoing, if there is any material change in any fact, information or matter affecting the Fairness Opinion after the date hereof, we reserve the right to change, modify or withdraw the Fairness Opinion. This Fairness Opinion is addressed to and is for the sole use and benefit of the Board of Directors of the General Partner, and may not be referred to, summarized, circulated, publicized or reproduced by the Company, other than in the Partnership Circular as herein expressly specified, or disclosed to, used or relied upon by any other party without the express prior written consent of Greenhill. This Fairness Opinion is not to be construed as a recommendation to the Board of Directors of the General Partner as to whether they should approve the Agreement and/or the Arrangement nor to any holder of Partnership Units as to whether or not to vote in favour of the Arrangement or take any other action in respect of its Partnership Units.

        We believe that our analyses must be considered as a whole and that selecting portions of our analyses or the factors considered by us, without considering all factors and analyses together, could create a misleading view of the process underlying the Fairness Opinion. The preparation of a Fairness Opinion is a complex process and is not necessarily susceptible to partial analysis or summary description. Any attempt to do so could lead to undue emphasis on any particular factor or analysis.

        Based on and subject to the foregoing, including the limitations and assumptions set forth herein and such other matters as we considered relevant, we are of the opinion that, as of the date hereof, the Consideration to be received by the holders of Partnership Units (other than Purchaser, the General Partner and the Corporation) under the Arrangement, is fair from a financial point of view, to such holders.

  Very best regards,

 

/S/ GREENHILL & CO. CANADA LTD.

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Annex F
Atlantic Power Corporation's
Share Issuance Resolution

To be provided by amendment.

Annex F-1


Table of Contents


Annex G
CPILP's Arrangement Resolution

To be provided by amendment.

Annex G-1


Table of Contents


Annex H
Interim Order

To be provided by amendment.

Annex H-1


Table of Contents


Annex I
Notice of Application for Final Order

To be provided by amendment.

Annex I-1


Table of Contents


Annex J
Form of Atlantic Power's Proxy Card


Table of Contents

LOGO


PROXY FOR REGISTERED HOLDERS OF COMMON SHARES

        This proxy is being solicited by or on behalf of management of Atlantic Power Corporation ("Atlantic Power") from holders of common shares of Atlantic Power ("Shareholders") for use in connection with the special meeting (the "Meeting") of Shareholders to be held on                        , 2011 at the King Edward Hotel,                        , 37 King Street East, Toronto, Ontario at             a.m. (Toronto time). Reference is made to the accompanying management proxy circular and joint proxy statement of Atlantic Power and Capital Power Income L.P. dated                        , 2011 (the "Circular") for further information.

        The undersigned Shareholder of Atlantic Power hereby appoints IRVING GERSTEIN or, failing him, JOHN McNEIL (or instead of either of them                         ), as proxy of the undersigned to attend and vote at the Meeting and at any adjournment or postponement thereof, with full power of substitution and with all the powers which the undersigned could exercise if personally present and with authority to vote at the said proxyholder's discretion unless herein otherwise specified. The said proxyholder is hereby specifically directed to:

        VOTE FOR o or VOTE AGAINST o the approval, with or without variation, of an ordinary resolution, the full text of which is set forth in Annex F to the accompanying Circular, authorizing Atlantic Power to issue such number of common shares in the capital of Atlantic Power as is necessary to complete the Arrangement, being 1.3 Atlantic Power common shares for each Capital Power Income L.P. unit to a maximum of 31,500,221 Atlantic Power common shares pursuant to the terms of the arrangement agreement dated June 20, 2011, as amended effective July 25, 2011, among Capital Power Income L.P., CPI Income Services Ltd., CPI Investments Inc. and Atlantic Power, a copy of which is included as Annex A to the accompanying Circular (all as more particularly described in the accompanying Circular).

        The undersigned hereby acknowledges receipt of the notice of the Meeting and the Circular.

DATED this              day of                                     , 2011.    


 

 

 
Name of Shareholder    


 

 

 
Signature of Shareholder
   

NOTES:

1.
The shares represented by this proxy will be voted for, voted against or withheld from voting (as applicable) in accordance with the instructions noted hereon on any ballot that may be called for. In the absence of instructions to the contrary, the shares will be voted "FOR" the above-mentioned matter. Management of Atlantic Power presently knows of no matters to come before the Meeting other than the matter(s) identified in the notice of the Meeting. If any amendments, variations or other matters should properly come before the Meeting, the shares represented by this proxy will be voted on such amendments, variations to matters identified in the notice of Meeting and other matters which may properly come before the Meeting in the discretion of the proxyholder named herein.

Annex J-1


Table of Contents

2.
To vote this proxy, the Shareholder must sign in the space provided on this form. Please sign exactly as the name appears hereon and in which the shares are registered. If the Shareholder is a corporation, the proxy should be executed by duly authorized officers and its corporate seal must be affixed. If this proxy is not dated in the space provided, the proxy shall be deemed to bear the date on which it was mailed by Atlantic Power.

3.
To be valid, this proxy must be signed and deposited with Computershare Trust Company of Canada, Proxy Department, 9th Floor, 100 University Avenue, Toronto, Ontario, M5J 2Y1, so that it is received by Computershare Trust Company of Canada not less than 48 hours, excluding Saturdays, Sundays and holidays, before the time fixed for holding the Meeting or any adjournments or postponements thereof.

4.
The Shareholder has the right to appoint a person, other than the persons designated in this proxy, to attend, vote and act for the Shareholder and on the Shareholder's behalf at the Meeting. Such right may be exercised by striking out the names of the specified persons and inserting the name of such other person in the space provided.

5.
This proxy revokes all prior proxies given by the Shareholder represented by this proxy and may be revoked at any time before it has been exercised.

6.
Reference should be made to the Circular, which accompanies the notice of Meeting, for a full explanation of the rights of Shareholders regarding completion and use of this proxy and other information pertaining to the Meeting.

Annex J-2


Table of Contents


Annex K
Form of CPILP's Proxy Card


Table of Contents


CAPITAL POWER INCOME L.P.

PROXY

FOR USE BY HOLDERS OF LIMITED PARTNERSHIP UNITS AT THE
SPECIAL MEETING OF UNITHOLDERS TO BE HELD ON                , 2011

        The undersigned holder (the "Unitholder") of limited partnership units ("Units") of Capital Power Income L.P. (the "Partnership"), hereby appoints Stuart A. Lee, President and a Director of CPI Income Services Ltd. (the "General Partner"), the general partner of the Partnership, or, failing him, Anthony Scozzafava, Chief Financial Officer of the General Partner, or instead of either of the foregoing,                                                                                                                      , as proxy holder for the undersigned, with full power of substitution, to attend, act and vote for and on behalf of the undersigned at the special meeting (the "Meeting") of Unitholders of the Partnership to be held on                , 2011, and at any adjournment thereof, in the same manner, to the same extent and with the same powers as if the undersigned were present at the Meeting or any adjournment thereof, with the authority to vote at the proxyholder's discretion except as otherwise specified below.

        Without limiting the general powers hereby conferred, the undersigned hereby directs the proxyholder to vote the Units represented by this proxy in the following manner:

        This proxy is solicited by management of the General Partner and the costs of same will be borne by the Partnership. The Units represented by this form of proxy will be voted, if the Unitholder has given direction above, as directed, or, if no direction is given, FOR the above proposal. The undersigned hereby confers discretionary authority upon such proxy holder to vote, in accordance with his/her best judgment, with respect to amendments or variations to the matters outlined above and with respect to matters other than those listed in the Notice of Special Meeting of Unitholders (the "Notice of Meeting") calling the Meeting and which may properly come before the Meeting or any adjournment thereof. At the date hereof, management of the General Partner knows of no such amendment, variation or other matter. This form of proxy should be read in conjunction with the accompanying Notice of Meeting and Information Circular.

        The undersigned hereby revokes any instrument of proxy previously given and does hereby further ratify all the proxyholder may lawfully do in the premises.

        DATED this              day of                                     , 2011.

   
Signature of Unitholder

 

 


Name of Unitholder (Please Print)

 

 



Number of Units Owned

SEE IMPORTANT INFORMATION IN THE NOTES ON BACK

Annex K-1


Table of Contents

NOTES:

1.
A UNITHOLDER HAS THE RIGHT TO APPOINT A PERSON OR COMPANY, WHO NEED NOT BE A UNITHOLDER, TO ATTEND AND ACT ON THE UNITHOLDER'S BEHALF AT THE SPECIAL MEETING OTHER THAN THE PERSONS DESIGNATED IN THIS FORM OF PROXY. THIS RIGHT MAY BE EXERCISED BY INSERTING SUCH OTHER PERSON'S NAME IN THE BLANK SPACE PROVIDED FOR THAT PURPOSE OR BY COMPLETING ANOTHER PROPER FORM OF PROXY AND, IN EITHER CASE, BY DELIVERING THE COMPLETED FORM OF PROXY TO THE PARTNERSHIP AS INDICATED BELOW.

2.
This form of proxy must be dated and must be executed by the Unitholder or the Unitholder's attorney authorized in writing or, if the Unitholder is a body corporate, under its corporate seal or by an officer or attorney thereof duly authorized. A copy of such authorization should accompany this form of proxy. Persons signing as executors, administrators, trustees, etc. should so indicate.

3.
In order for this form of proxy to be effective at the Meeting or any adjournment thereof, it must be signed and dated and delivered or mailed to the Partnership's registrar and transfer agent, Computershare Trust Company of Canada at 9th Floor, 100 University Ave, Toronto, Ontario, M5J 2Y1, Attention: Proxy Department, not less than 48 hours, excluding Saturdays, Sundays and statutory holidays, prior to the time of the Meeting or any adjournment thereof.

Annex K-2


Table of Contents


Schedule I

Annual Report of Atlantic Power on Form 10-K
for the Year Ended December 31, 2010


Table of Contents

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549



FORM 10-K




ý

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

OR

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                           to                          

Commission file number 001-34691

ATLANTIC POWER CORPORATION
(Exact Name of Registrant as Specified in its Charter)

British Colombia, Canada   55-0886410
(State of Incorporation)   (I.R.S. Employer Identification No.)

200 Clarendon St, Floor 25
Boston, MA

 


02116
(Address of Principal Executive Offices)   (Zip Code)

(617) 977-2400
(Registrant's Telephone Number, Including Area Code)

         Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class   Name of Each Exchange on Which Registered
Common Shares, no par value per share   The New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Act: None



         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

         Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes    o No

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer o   Accelerated Filer o   Non-Accelerated Filer ý
(Do not check if a
smaller reporting company)
  Smaller reporting company o

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         As of March 15, 2011, the aggregate market value of the 67,853,964 Common Shares, no par value per share, held by non-affiliates of the registrant was $1,035.5 million based upon the last reported sale price of $15.26 on the New York Stock Exchange. For purposes of the foregoing calculation only, all directors and executive officers of the registrant have been deemed affiliates.

         As of March 18, 2011, 68,108,042 of the registrant's Common Shares were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's definitive Proxy Statement for its 2011 Annual Meeting of Shareholders, to be filed not later than 120 days after the end of the registrant's fiscal year, are incorporated by reference into Items 10 through 14 of Part III of this Annual Report on Form 10-K.

Schedule I-1


Table of Contents


TABLE OF CONTENTS

PART I

   

ITEM 1.

 

BUSINESS

  I-3

ITEM 1A.

 

RISK FACTORS

  I-38

ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

  I-50

ITEM 2.

 

PROPERTIES

  I-50

ITEM 3.

 

LEGAL PROCEEDINGS

  I-50

ITEM 4.

 

(Removed and Reserved)

  I-50

PART II

   

ITEM 5.

 

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

  I-51

ITEM 6.

 

SELECTED FINANCIAL DATA

  I-52

ITEM 7.

 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

  I-53

ITEM 7A.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  I-78

ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  I-82

ITEM 9.

 

CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  I-82

ITEM 9A.

 

CONTROLS AND PROCEDURES

  I-82

ITEM 9B.

 

OTHER INFORMATION

  I-82

PART III

   

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

  I-83

ITEM 11.

 

EXECUTIVE COMPENSATION

  I-83

ITEM 12.

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

  I-83

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

  I-83

ITEM 14.

 

PRINCIPAL ACCOUNTING FEES AND SERVICES

  I-83

PART IV

   

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

  I-83

        As used herein, the terms "Atlantic Power," the "Company," "we," "our," and "us" refer to Atlantic Power Corporation, together with those entities owned or controlled by Atlantic Power Corporation, unless the context indicates otherwise. All references to "Cdn$" and "Canadian dollars" are to the lawful currency of Canada and references to "$," "US$" and "U.S. dollars" are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise indicated.

Schedule I-2


Table of Contents


PART I

ITEM 1.    BUSINESS

OVERVIEW

        Atlantic Power Corporation owns interest in 13 operational power generation projects across ten states, one biomass project under construction in Georgia, a 500 kilovolt 84-mile electric transmission line located in California and several development projects. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,962 megawatts ("MW"), in which our ownership interest is approximately 878 MW.

        The following map shows the location of our projects, including joint venture interests, across the United States:

GRAPHIC

        We sell the capacity and energy from our projects under power purchase agreements ("PPAs") with a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2011 to 2037, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). We also sell steam from a number of our projects under steam sales agreements to industrial purchasers. The transmission system rights we own in our power transmission project entitle us to payments indirectly from the utilities that make use of the transmission line.

        Our projects generally operate pursuant to long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the terms of the fuel supply and

Schedule I-3


Table of Contents


transportation arrangements correspond to the terms of the relevant PPAs. Many of the PPAs and steam sales agreements provide for the pass-through or indexing of fuel costs to our customers.

        We partner with recognized leaders in the power business to operate and maintain our projects, including Caithness Energy ("Caithness"), Power Plant Management Services ("PPMS"), Delta Power Services and the Western Area Power Administration ("Western"). Our asset management team works with these operators to proactively pursue opportunities to both improve the performance of our physical assets and optimize the various project contracts for enhanced financial performance.

        Atlantic Power Corporation is organized under the laws of the Province of British Columbia. Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia, Canada V6C 2G8 and our headquarters are located at 200 Clarendon Street, Floor 25, Boston, Massachusetts, USA 02116. Our website is www.atlanticpower.com. Information contained on our website is not part of this Form 10-K.

        We completed our initial public offering on the Toronto Stock Exchange ("TSX") in November 2004. At the time of our initial public offering, or IPO, our publicly traded security was an income participating security ("IPS") comprised of one common share and Cdn$5.767 principal value of 11% subordinated notes due 2016. On November 17, 2009, our shareholders approved a conversion from the IPS structure to a traditional common share structure. Each IPS was exchanged for one new common share and each old common share that did not form part of an IPS was exchanged for approximately 0.44 of a new common share. Our shares trade on the TSX under the symbol "ATP" and began trading on July 23, 2010 on the New York Stock Exchange ("NYSE") under the symbol "AT".


HISTORY OF OUR COMPANY

        Atlantic Power Corporation is a Canadian corporation that was formed in 2004. The following timeline illustrates significant events in the development of our business since our initial public offering. Further details about these events are included below:

GRAPHIC

Schedule I-4


Table of Contents

        We used the proceeds from our IPO to acquire a 58% interest in Atlantic Power Holdings, LLC (now Atlantic Power Holdings, Inc., which we refer to herein as "Atlantic Holdings") from two private equity funds managed by ArcLight Capital Partners, LLC and from Caithness. Until December 31, 2009, we were externally managed by Atlantic Power Management, LLC, an affiliate of ArcLight. Under this external management arrangement, ArcLight provided administrative and office support services to us and was required to give us the opportunity to pursue investment opportunities that did not fit ArcLight's investment guidelines for its private equity funds. At the time of our IPO, Atlantic Holdings was granted a right of first offer related to ArcLight's interest in 11 power generating projects. Our acquisitions of a 40% interest in the Chambers project in 2005 and the Auburndale project in 2008 were completed under the terms of this right of first offer, which has since expired.

        In August 2005, we acquired Epsilon Power Partners, LLC, which owns a 40% interest in the Chambers project, for approximately $63 million in cash and the assumption of $43 million in non-recourse debt.

        In October 2005, we completed a private placement of 7,500,000 IPSs. We used the net proceeds of the private placement to increase our ownership in Atlantic Holdings to 70.1%.

        In September 2006, we acquired 100% of the equity interests in Trans-Elect NTD Holdings Path 15, LLC (Path 15), which has since been renamed Atlantic Path 15 Holdings, LLC and indirectly owns approximately 72% of the transmission system rights in the transmission line upgrade along the Path 15 transmission corridor located in central California. The purchase price was approximately $78.4 million.

        In October 2006, we completed a sale of 8,531,000 IPSs and debentures for gross proceeds of Cdn$150 million. The IPSs were sold at a price of Cdn$10.55 per IPS for gross proceeds of Cdn$90 million and Cdn$60 million aggregate principal amount of debentures were issued. The IPSs and debentures were sold on a bought deal basis to a syndicate of underwriters. We used the net proceeds in February 2007 to acquire all of the remaining interest of ArcLight and Caithness in Atlantic Holdings.

        In December 2006, we completed a private placement of 8,600,000 IPSs and Cdn$3.0 million principal amount of separate subordinated notes to three institutional investors. In February 2007, we used the net proceeds of the private placement to increase our ownership in Atlantic Holdings to 100%.

        In November 2008, we acquired a 100% ownership interest in Auburndale Power Partners, L.P, which owns the Auburndale project, for a purchase price of approximately $140.0 million. The acquisition was funded with cash on hand, a $55 million borrowing under our credit facility and non-recourse acquisition debt of $35 million. The non-recourse acquisition debt associated with this transaction amortizes fully over the remaining term of the project's power purchase agreement, which expires in 2013. The borrowing under the credit facility was repaid in 2009.

        In the first quarter of 2009, we transferred our remaining net interest in Onondaga Cogeneration Limited Partnership, at net book value, into a 50% owned joint venture, Onondaga Renewables, LLC, which is engaged in the redevelopment of the Onondaga project into a 40 MW biomass power plant.

        In March 2009, we acquired a 40% equity interest in Rollcast Energy, Inc., a North Carolina corporation. Rollcast is a developer of biomass power plants in the southeastern U.S. with a number of additional 50 MW projects in various stages of development. We agreed to invest $2.0 million in March 2010 to increase our ownership interest in Rollcast to 60%. Under the terms of the agreement, $1.2 million of the investment was made in March 2010 and the remaining $0.8 million was made in April 2010. As a result of this additional investment, we began to consolidate our investment in Rollcast beginning March 1, 2010. We have the option, but not the obligation, to invest directly in biomass power plants developed by Rollcast.

Schedule I-5


Table of Contents

        In October 2009, we agreed to pay ArcLight an aggregate of $15 million to terminate its management agreement with us, satisfied by a payment of $6 million on the termination date of December 31, 2009, and additional payments of $5 million, $3 million and $1 million on the respective first, second and third anniversaries of the termination date. In connection with the termination of the management agreements, we hired all of the then-current employees of Atlantic Power Management and entered into employment agreements with its officers.

        In December 2009, we issued, in a public offering, 6.25% convertible unsecured subordinated debentures due March 15, 2017, the 2009 Debentures, at a price of Cdn$1,000 per debenture for total gross proceeds of Cdn$86.25 million. The 2009 Debentures are convertible at any time, at the option of the holder, into approximately 76.9231 common shares per Cdn$1,000 principal amount of the 2009 Debentures, representing a conversion price of Cdn$13.00 per common share. Approximately Cdn$42.9 million of the net proceeds from the offering were used to redeem our 11% subordinated notes. The remainder of the net proceeds was made available to fund growth opportunities including biomass development and for general corporate purposes.


RECENT DEVELOPMENTS

        On July 2, 2010, we acquired a 27.6% equity interest in Idaho Wind Partners 1, LLC ("Idaho Wind") for approximately $40.0 million. Idaho Wind recently completed construction of a 183 MW wind power project located near Twin Falls, Idaho. Idaho Wind has 20-year PPAs with Idaho Power Company. Our investment in Idaho Wind was funded with cash on hand and a $20.0 million borrowing under our credit facility, which was subsequently paid in full in November 2010. We made a short-term $22.8 million loan to Idaho Wind to provide temporary funding for construction of the project until a portion of the project-level construction financing is completed. See additional details on page 28. Member loans will be paid down with a combination of excess proceeds from the federal stimulus cash grant after repaying the cash grant loan facility, funds from a third closing for additional project-level debt, and project cash flow. The federal stimulus grant is expected in the second quarter of 2011 and a third closing is expected by the end of the year. As of March 18, 2011, $5.1 million of the loan has been repaid. Our investment in Idaho Wind is accounted for under the equity method of accounting.

        On October 20, 2010, we completed a public offering of 6,029,000 common shares, including 784,000 common shares issued pursuant to the exercise in full of the underwriters' over-allotment option, at a price of $13.35 per common share. We received net proceeds from the common share offering, after deducting the underwriting discounts and expenses, of approximately $75.3 million.

        On October 20, 2010, we also completed the closing of a public offering of Cdn$80.5 million aggregate principal amount of convertible unsecured subordinated debentures at a price of Cdn$1,000 per debenture, including Cdn$10.5 million aggregate principal amount of debentures pursuant to the exercise in full of the underwriters' over-allotment option. The debentures bear interest at a rate of 5.60%, and will mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion rate of 55.2486 common shares per Cdn$1,000 principal amount of debentures, representing an initial conversion price of approximately Cdn$18.10 per common share (equivalent to US$18.03 per common share). We received net proceeds from the debenture offering, after deducting the underwriting discounts and expenses, of approximately Cdn$76.1 million ($74.6 million). The net proceeds from these offerings were used as follows: (i) approximately US$20.0 million to repay indebtedness incurred under our credit facility entered into in June 2010 to partially fund acquisition of a 27.6% equity interest in Idaho Wind, and (ii) approximately US$75.0 million to fund an investment in the Piedmont Green Power project for substantially all of the equity interest in the project. Any remaining net proceeds were used to fund the Cadillac acquisition and for general corporate purposes.

Schedule I-6


Table of Contents

        In November 2010, we closed the construction and term financing for the Piedmont Green Power, LLC ("Piedmont") project, a 53.5 MW biomass project located in Barnesville, Georgia and we agreed to invest approximately $75.0 million in the project to own substantially all of the equity interests. Construction of the project commenced immediately following the financial closing. The Piedmont Green Power project has a 20-year PPA with Georgia Power Company which includes an adjustment related to the cost of biomass fuel for the plant.

        On December 20, 2010, we closed the acquisition of 100% of the membership interests in Cadillac Renewable Energy, LLC ("Cadillac"), a 39.6 MW biomass-fired generating facility located in Cadillac, Michigan that has been operating since 1993. The purchase price of approximately $80.0 million was funded by $37.0 million using a portion of the cash raised in the public equity and convertible debenture offerings in October 2010 and $43.0 million of assumed non-recourse, project-level debt.


OUR COMPETITIVE STRENGTHS

Schedule I-7


Table of Contents


OUR OBJECTIVES AND BUSINESS STRATEGY

        Our objectives include maintaining the stability and sustainability of dividends to shareholders and to maximize the value of our company. In order to achieve these objectives, we intend to focus on enhancing the operating and financial performance of our current projects and pursuing additional accretive acquisitions primarily in the electric power industry in the United States and Canada.


Organic growth

        We intend to enhance the operation and financial performance of our projects through:


Extending PPAs following their expiration

        PPAs in our portfolio have expiration dates ranging from 2011 to 2037. In each case, we plan for expirations by evaluating various options in the market for maximizing long-term project cash flows and passing through to purchasers as effectively as possible the potential changes in fuel costs. New arrangements may involve responses to utility solicitations for capacity and energy, direct negotiations with the original purchasing utility for PPA extensions, "reverse" request for proposals by the projects to likely bilateral counterparty arrangements with creditworthy energy trading firms for tolling agreements, full service PPAs or the use of derivatives to lock in value. We do not assume that revenues or operating margins under existing PPAs will necessarily be sustained after PPA expirations, since most original PPAs included capacity payments related to return of and return on original capital invested, and counterparties or evolving regional electricity markets may or may not provide similar payments under new or extended PPAs.


Acquisition and investment strategy

        We believe that new electricity generation projects will be required in the United States and Canada over the next several years as a result of growth in electricity demand, transmission constraints and the retirement of older generation projects due to obsolescence or environmental concerns. In addition, Renewable Portfolio Standards in over 31 states and the recently extended American Recovery and Reinvestment Act's 1603 grant program have greatly facilitated strong PPAs and financial returns for significant renewable project opportunities. There is also a very active secondary market for existing projects.

        We intend to expand our operations by making accretive acquisitions with a focus on power generation, transmission, distribution and related facilities in the United States and Canada. We may also invest in other forms of energy-related projects, utility projects and infrastructure projects, as well

Schedule I-8


Table of Contents


as make additional investments in development stage projects or companies where the prospects for creating long-term predictable cash flows are attractive. Since the time of our initial public offering on the TSX in late 2004, we have twice acquired the interest of another partner in one of our existing projects and will continue to look for such opportunities.

        Our senior management has significant experience in the independent power industry and we believe that their experience, reputation and industry relationships will provide us with enhanced access to future acquisition opportunities on a proprietary basis.


Acquisition guidelines

        We use the following general guidelines when reviewing and evaluating possible acquisitions:


POWER INDUSTRY OVERVIEW

        Historically, the North American electricity industry was characterized by vertically-integrated monopolies. During the late 1980s, several jurisdictions began a process of restructuring by moving away from vertically integrated monopolies toward more competitive market models. Rapid growth in electricity demand, environmental concerns, increasing electricity rates, technological advances and other concerns prompted government policies to encourage the supply of electricity from independent power producers.

        In the independent power generation sector, electricity is generated from a number of energy sources, including natural gas, coal, water, waste products such as biomass (e.g., wood, wood waste, agricultural waste), landfill gas, geothermal, solar and wind. According to the North American Electric Reliability Council's Long-Term Reliability Assessment, published in December 2009, summer peak demand within the United States in the ten-year period from 2010 through 2019 is projected to increase 1.3%, while winter peak demand in Canada is projected to increase 0.9%.


The non-utility power generation industry

        Our 13 power generation projects are non-utility electric generating facilities that operate in the U.S. electric power generation industry. The electric power industry is one of the largest industries in the United States, generating retail electricity sales of approximately $353 billion in 2009, based on information published by the Energy Information Administration. A growing portion of the power produced in the United States is generated by non-utility generators. According to the Energy Information Administration, there were approximately 8,448 non-utility generators representing approximately 475 gigawatts of capacity (equal to 47% of total generating plants and 42% of nameplate capacity) in 2009, the most recent year for which data is available. Non-utility generators sell the electricity that they generate to electric utilities and other load-serving entities (such as municipalities and electric cooperatives) by way of bilateral contracts or open power exchanges. The electric utilities and other load-serving entities, in turn, generally sell this electricity to industrial, commercial and residential customers.

Schedule I-9


Table of Contents


OUR POWER PROJECTS

        The following table outlines our portfolio of power generating and transmission assets in operation and under construction as of March 18, 2011, including our interest in each facility. Management believes the portfolio is well diversified in terms of electricity and steam buyers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region.


 
Project Name
  Location
(State)

  Type
  Total
MW

  Economic
Interest(1)

  Net
MW(2)

  Electricity
Purchaser

  Power
Contract
Expiry

  Customer
S&P Credit
Rating


 

Auburndale

  Florida   Natural Gas     155     100.00 %   155   Progress Energy Florida     2013   BBB+

 

Lake

  Florida   Natural Gas     121     100.00 %   121   Progress Energy Florida     2013   BBB+

 

Pasco

  Florida   Natural Gas     121     100.00 %   121   Tampa Electric Co.     2018   BBB

 

Chambers

  New Jersey   Coal     262     40.00 %   89   ACE(3)     2024   BBB
                         
 

                        16   DuPont     2024   A

 

Path 15

  California   Transmission     N/A     100.00 %   N/A   California Utilities via CAISO(4)     N/A (5) BBB+ to A(6)

 

Orlando

  Florida   Natural Gas     129     50.00 %   46   Progress Energy Florida     2023   BBB+
                         
 

                        19   Reedy Creek Improvement District     2013 (7) A-(8)

 

Selkirk

  New York   Natural Gas     345     17.70 %(9)   15   Merchant     N/A   N/R
                         
 

                        49   Consolidated Edison     2014   A-

 

Gregory

  Texas   Natural Gas     400     17.10 %   59   Fortis Energy Marketing and Trading     2013   A-
                         
 

                        9   Sherwin Alumina     2020   NR

 

Topsham(10)

  Maine   Hydro     14     50.00 %   7   Central Maine Power     2011   BBB+

 

Badger Creek

  California   Natural Gas     46     50.00 %   23   Pacific Gas & Electric     2011 (11) BBB+

 

Koma Kulshan

  Washington   Hydro     13     49.80 %   6   Puget Sound Energy     2037   BBB

 

Delta-Person

  New Mexico   Natural Gas     132     40.00 %   53   PNM     2020   BB-

 

Cadillac

  Michigan   Biomass     40     100.00 %   40   Consumers Energy     2028   BBB-

 

Idaho Wind(12)

  Idaho   Wind     183     27.56 %   50   Idaho Power Co.     2030   BBB

 

Piedmont(13)

  Georgia   Biomass     54     98.00 %   53   Georgia Power     2032   A

 

(1)
Except as otherwise noted, economic interest represents the percentage ownership interest in the project held indirectly by Atlantic Power.
(2)
Represents our interest in each project's electric generation capacity based on our economic interest.
(3)
Includes a separate power sales agreement in which the project and ACE share profits on spot sales of energy and capacity not purchased by ACE under the base PPA.
(4)
California utilities pay transmission access charges to the California Independent System Operator, who then pays owners of Transmission system rights, such as Path 15, in accordance with its annual revenue requirement approved every three years by FERC.
(5)
Path 15 is a FERC regulated asset with a FERC-approved regulatory life of 30 years: through 2034.
(6)
Largest payers of transmission access charges supporting Path 15's annual revenue requirement are Pacific Gas & Electric (BBB+), Southern California Edison (BBB+) and San Diego Gas & Electric (A). the California Independent System Operator imposes minimum credit quality requirements for any participants rated A or better unless collateral is posted per the California Independent System Operator imposed schedule.
(7)
Upon the expiry of the Reedy Creek PPA, the associated capacity and energy will be sold to PEF.
(8)
Fitch rating on Reedy Creek Improvement District bonds.
(9)
Represents our residual interest in the project after all priority distributions are paid to us and the other partners, which is estimated to occur in 2012. For further details, see project description.
(10)
We currently own our interest in this project as a lessor, but our lessor interest is subject to a purchase and sale agreement entered into with a third party on February 28, 2011.
(11)
Expect an interim agreement to be entered into while details of a long-term agreement are worked out.
(12)
Project just reached commercial operations and operating at initially reduced start-up levels.
(13)
Project currently under construction and is expected to be completed in late 2012.

Schedule I-10


Table of Contents

        The following corporate organization chart includes all of our operating and development projects:

GRAPHIC

        Our projects are organized into the following six business segments:

•       Auburndale

 

•        Chambers

•       Lake

 

•        Path 15

•       Pasco

 

•        Other Project Assets


Auburndale segment

        The Auburndale segment consists of a 155 MW dual-fired (natural gas and oil), combined-cycle, cogeneration plant located in Polk County, Florida, which commenced operations in July 1994. We own 100% of the Auburndale project, which is a "qualifying facility" (or "QF") under the rules promulgated by FERC. We acquired Auburndale from ArcLight Energy Partners Fund I, L.P. and Calpine Corporation in a transaction that was completed on November 21, 2008.

        Auburndale is located on an 11-acre site in the City of Auburndale, Florida. Capacity and energy from the project is sold to Progress Energy Florida, Inc. ("PEF") under three PPAs expiring at the end of 2013. Auburndale typically operates during on-peak periods. Steam is supplied to Florida Distillers Company and Cutrale Citrus Juices USA, Inc. The Florida Distillers steam agreement is renewed annually, and the Cutrale Citrus Juices steam agreement expires in 2013.

        Auburndale has non-recourse debt outstanding of $21.7 million as of December 31, 2010 which is required to be fully amortized over the term of its PPAs expiring in 2013. See "Project-level debt" on page 72 of this Form 10-K for additional details. Atlantic Power has provided letters of credit in the

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total amount of $13.4 million to support certain Auburndale obligations: $5.5 million to support its debt service reserve, $4.4 million to support its PPAs, and $3.5 million to support its fuel supply agreement.

        Auburndale sells capacity and electricity to PEF under three PPAs each of which expires on December 31, 2013. Under the largest of the PPAs, Auburndale sells 114 MW of capacity and energy. An additional 17 MW of committed capacity is sold under two identical 8.5 MW agreements with PEF. Revenue from the sale of electricity under the three PPAs consists of capacity payments based on a fixed schedule of prices, and energy payments. Capacity payments under the largest PPA are dependent on the plant maintaining a minimum on-peak capacity factor of 92 percent on a rolling twelve-month average basis. On-peak capacity factor refers to the ratio of actual electricity generated during periods of peak demand to the capacity rating of the plant during such periods. The project has achieved the minimum on-peak capacity factor continuously since commercial operation. Capacity payments under the smaller two agreements are dependent on the project maintaining a minimum on-peak capacity factor of 70 percent. Energy payments under the largest PPA are comprised of a fuel component based on the cost of coal consumed at two PEF-owned coal-fired generating stations and a component intended to recover operating and maintenance costs. Energy payments under the smaller two agreements are based on the lesser of PEF's actual avoided energy cost or an energy price index based on the cost of fuel burned at a specific coal-fired power plant owned by TECO.

        Auburndale entered into an agreement with TECO to transmit electric energy from the project to PEF. The agreement expires in 2024, unless extended as provided for in the agreement. Auburndale's cost for these services is based on a contractual formula derived from TECO's cost of providing such services.

        Auburndale provides steam to Florida Distillers and Cutrale Citrus Juices under two separate steam purchase agreements. The Florida Distillers agreement automatically extends on an annual basis, and can be terminated by either party with 90 days notice. The Cutrale Citrus Juices agreement terminates on December 31, 2013 and contains automatic two-year renewal terms.

        Auburndale receives the majority of its required natural gas through a gas supply agreement with El Paso Merchant Energy, L.P. that expires on June 30, 2012. Under the agreement, El Paso provides a fixed amount of gas on a daily basis. The gas price escalates annually and is below current market prices. At historic utilization rates, the gas supplied under the El Paso contract has accounted for approximately 80% of the gas required by the project under its PPA commitments and the remaining required fuel is purchased at spot prices.

        The required natural gas for the project is delivered through firm gas transportation agreements with Central Florida Gas Company ("Florida Gas") and Florida Gas Transmission Company and is transported through the gas distribution system owned by Peoples Gas Transmission, Inc. ("Peoples Gas"). The gas transportation agreements are co-terminous with the PPAs, expiring on December 31, 2013.

        During the term of the gas supply agreement, approximately 80% of the natural gas required to fulfill the project's PPAs is purchased at fixed prices. The remainder of the natural gas is purchased on the spot market. As a result, the project's operating margin is exposed to changes in spot market natural gas prices because the PPAs do not pass through those price changes to PEF. In order to mitigate this risk, Auburndale has entered into a series of financial swaps that effectively fix most of the price of natural gas to be purchased. See Item 7A "Quantitative and Qualitative Disclosure About Market Risk" for a summary of the hedge position related to natural gas requirements at Auburndale.

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        We will continue to periodically analyze whether to execute further hedge transactions intended to mitigate natural gas price exposure at Auburndale through the expiration of the PPAs with PEF.

        The Auburndale project is operated and maintained by an affiliate of Caithness. In 2006, Auburndale entered into a maintenance agreement with Siemens Energy, Inc. for the long-term supply of certain parts, repair services and outage services related to the gas turbine. The term of the maintenance agreement is dependent on the timing of completion of a certain number of maintenance inspections. The final maintenance event under the agreement is scheduled for late 2012, with the final monthly payment under the agreement scheduled for September 2013.

        Auburndale derives a significant portion of its revenue through capacity payments received under the PPAs with PEF. In the event the project's on-peak capacity factor falls below a specified level, capacity payments will be adjusted downward or terminated altogether. Since it began commercial operation in 1994, the project has received full capacity payments.

        The energy portion of Auburndale's revenue under the PPA with PEF is impacted by changes in the price of coal used by two of their power plants in Florida. Because these power plants secure a significant portion of their coal through contracts of varying lengths, the price of coal burned at those plants does not move in tandem with changes in spot coal prices.


Lake segment

        The Lake segment consists of a 121 MW dual-fuel, combined-cycle QF cogeneration plant located in Umatilla Florida, which began commercial operation in July 1993. We own 100% of the Lake project. In late 2007, the existing combustion turbines at the facility were upgraded to increase their efficiency by approximately 4% and output from 110 MW to 121 MW.

        The Lake project is located on a 16-acre site leased from an adjacent citrus processing facility in Umatilla, Florida. Lake sells all of its capacity and electric energy to Progress Energy Florida, Inc. ("PEF") under the terms of a PPA expiring in July 2013. The project is generally operated as a mid-merit facility typically running during peak hours daily. Steam is sold to Citrus World, Inc. for use at its citrus processing facility and is also used to make distilled water in distillation units which is sold to various parties.

        The Lake project does not have any debt outstanding. Atlantic Power has provided a $4.3 million letter of credit in favor of PEF to support the Lake project's obligations under its PPA.

        Electricity is sold to PEF pursuant to a PPA that expires on July 31, 2013. Revenues from the sale of electricity consist of a fixed capacity payment and an energy payment. Capacity payments are subject to the project maintaining a capacity factor of at least 90% during on-peak hours (11 hours daily), on a 12-month rolling average basis. Lake is subject to reductions in its capacity payment should it not achieve the 90% on-peak capacity factor. The project generally has achieved the minimum on-peak capacity factor continuously since commercial operation. Energy payments are comprised of a fuel component based on the cost of coal consumed at two PEF-owned coal-fired generating stations, a component intended to recover operations and maintenance costs, a voltage adjustment and an hourly performance adjustment.

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        The Lake project provides steam to Citrus World under a steam purchase agreement that expires in 2013. The project also supplies steam to an affiliate that uses steam to make distilled water, which is sold to unaffiliated third parties.

        The natural gas requirements for the facility are provided by Iberdrola Renewables, Inc. and TECO Gas Services, Inc. ("TGS"). Both the Iberdrola and TGS agreements contain market index based prices, commenced on July 1, 2009 and expire on July 31, 2013. Natural gas is transported to the project from supply points in Texas, Louisiana and Mississippi to Florida under contracts with Peoples Gas System, Inc.

        The Lake project is operated and maintained by an affiliate of Caithness. Lake also has a long-term services agreement and a lease engine agreement in place with General Electric ("GE"). The long-term services agreement provides for planned and unplanned maintenance on the two gas turbines at the plant. Under the lease engine agreement, GE rapidly provides temporary replacement natural gas turbines to the project to support operations when the project's turbines are removed from the site for significant maintenance.

        The Lake project derives a significant portion of its operating margin through capacity revenues received under the PPA with PEF. In the event the facility's on-peak capacity factor falls below a specified level, capacity payments will be adjusted downward, although the project has rarely experienced such reductions. During the term of the current gas supply agreement, effective July 1, 2009, Lake's operating margins are exposed to changes in natural gas prices through the end of the PEF PPA in 2013. As a result, we have entered into a series of financial swaps that effectively fix most of the price of natural gas required by Lake, thereby substantially mitigating fuel price risk. See Item 7A "Quantitative and Qualitative Disclosures About Market Risk" for a summary of the hedge position related to natural gas requirements at Lake.

        We will continue to analyze whether to execute further hedge transactions to mitigate natural gas price exposure at Lake through expiration of the PPA with PEF.

        The energy portion of Lake's revenue under the PPA with PEF is impacted by changes in the price of coal used by two of their power plants in Florida. Because these power plants secure a significant portion of their coal through contracts of varying lengths, the price of coal burned at those plants does not move in tandem with changes in spot coal prices.

        Our Lake project is currently involved in a dispute with Progress Energy Florida over off-peak energy sales in 2010. All amounts billed for off-peak energy during 2010 by the Lake project have been paid in full by Progress. The Lake project has filed a claim against Progress in which we seek to confirm our contractual right to sell off-peak energy at the contractual price for such sales. Progress filed a counter-claim against the Lake project, seeking, among other things, the return of amounts paid for off-peak power sales during 2010 and a declaratory order clarifying Lake's rights and obligations under the PPA. The Lake project has stopped dispatching during off-peak periods and our forward guidance for distributions does not include proceeds from off-peak sales, pending the outcome of the dispute. However, we strongly believe that the court will confirm our contractual right to sell off-peak power using the contractual price that was used during 2010 and that we will be able to continue such off-peak power sales for the remainder of the term of the PPA. We have not recorded any reserves related to this dispute and expect that the outcome will not have a material adverse effect on our financial position or results of operations.

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Pasco segment

        The Pasco segment consists of the 100% owned Pasco project, a 121 MW dual fuel, combined-cycle cogeneration plant located in Dade City, Florida, which began commercial operations in 1993 as a QF. With the expiration of the original PPA with PEF in 2008, and the commencement of the tolling agreement with TECO in 2009, Pasco self-certified with the FERC as an exempt wholesale generator and was no longer required to maintain QF status. The project owns the 2.7 acre site approximately 45 miles north of Tampa, Florida.

        Electricity is sold to TECO pursuant to a tolling agreement that commenced on January 1, 2009 and expires on December 31, 2018. Under the tolling agreement, TECO purchases the project's capacity and energy conversion services. Pasco converts fuel supplied by a TECO affiliate into electricity. Revenues consist of capacity payments, start-up charges, variable payments based on the amount of electricity generated and heat rate bonus payments based on the actual efficiency of the plant versus the contract efficiency. Atlantic Power has provided a $10 million letter of credit in favor of TECO to support the project's obligations under the tolling agreement.

        In exchange for obtaining the right to sell any potential excess emissions allowances from the plant, TECO accepted financial responsibility for any future costs associated with obtaining additional allowances, offsets or credits required due to changes to environmental laws, including state or federal carbon legislation.

        Under the terms of the tolling agreement, TECO is responsible for the fuel supply and is financially responsible for fuel transportation to the project.

        The Pasco project is operated and maintained by an affiliate of Caithness. Pasco also has a services agreement and a lease engine agreement in place with GE. The services agreement provides for discounts for planned and unplanned maintenance on the project's two natural gas turbines, and commits the project to use GE for gas turbine maintenance activities. Under the lease engine agreement, GE rapidly provides temporary replacement natural gas turbines to the project to support operations when the project's turbines are removed from the site for significant maintenance.

        The Pasco project derives the majority of its revenues under the tolling agreement with TECO through capacity payments. In the event the project does not maintain certain levels of availability, the capacity payments will be reduced. Based on historical performance, we expect the project to continue to exceed the availability requirement of 93% in the summer and 90% in the winter. A portion of the project's operating margin is based on three variable payments from TECO, consisting of a variable operation and maintenance charge, a start charge and a heat rate bonus. As a result, the project achieves a variable margin during periods of operation; and as a result, the level of variable margin is impacted by how much the plant is called on to produce electricity.

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Chambers segment

        The Chambers segment consists of our 40% equity investment in the Chambers project, a 262 MW pulverized coal-fired cogeneration facility located at the E.I. du Pont de Nemours and Company Chambers Works chemical complex near Carney's Point, New Jersey, which began commercial operation in March 1994 as a QF. Affiliates of Goldman Sachs Group, Inc. and Energy Investors Funds, an established private equity fund manager that invests in the U.S. energy and electric power sector, in the aggregate hold 60% of the general partner interests. Chambers sells electricity to ACE under two separate power purchase agreements, a "Base PPA" and a power sales agreement. Historically, the project has operated as a baseload plant, however, during periods of low energy market pricing, the facility has run at partial or minimum load. Steam and electricity are sold to DuPont pursuant to an energy services agreement. The project site is leased from DuPont. Under the terms of the ground lease, DuPont has a right to purchase the project within 60 days of the lease expiration in 2024, or upon earlier termination of the lease, at fair market value.

        Chambers financed the construction of the project with a combination of term debt due March 31, 2014 and New Jersey Economic Development Authority bonds due July 1, 2021. The term loan amortizes over its remaining term, while the bonds are repayable at maturity. Both are non-recourse to Atlantic Power. Our 40% share of the total debt outstanding at the Chambers project as of December 31, 2010 is $75.0 million. See "Project-level debt" on page 72 of this Form 10-K for additional details.

        Epsilon Power Partners, L.P., our wholly-owned subsidiary, directly owns our interest in Chambers. Epsilon has outstanding debt of $36.5 million as of December 31, 2010 which fully amortizes by its final maturity in 2019 and is non-recourse to Atlantic Power. See "Project-level debt" on page 72 of this Form 10-K for additional details.

        The 30-year term of the Base PPA with ACE expires in 2024. ACE has agreed to purchase 184 MW of capacity and has dispatch rights for energy of up to 187.6 MW during the summer season (May 1 to October 31) and 173.2 MW during the winter season (November 1 to April 30) and a minimum dispatch level of 46 MW. The project must be available to deliver power to ACE at 90% of the average availability rate of a specific group of mid-Atlantic generating stations, which in 2010 was approximately 86.0%. Capacity prices are determined using a fixed price with a capacity factor adjustment. The energy payment under the Base PPA is divided between on-peak and off-peak periods and linked to a coal index that is identical to the project's coal supply contract escalation provisions. Chambers is guaranteed a minimum energy payment equivalent to 3,500 hours of operation per contract year, whether or not it has dispatched that many hours, provided the project is available for energy production for at least 3,500 hours during the course of the contract year.

        DuPont purchases all its electrical needs for its Chambers Works chemical complex from the Chambers project, subject to a peak requirement of 40 MW, under the energy services agreement ("ESA"). The initial term of the agreement expires in 2024 but will continue thereafter unless terminated by at least 36 months prior written notice. The electricity sold under the ESA contains a fixed price, which is adjusted quarterly by the lesser of either: (i) the price of coal delivered to the facility; and (ii) the change in ACE's average retail rate.

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        In December 2008, Chambers filed suit against DuPont for breach of the ESA related to unpaid amounts associated with disputed price change calculations for electricity. DuPont subsequently filed a counterclaim for an unspecified level of damages. In February 2011, Chambers received a favorable ruling from the court on its summary judgment motion as to liability. The court's decision included a description of the pricing methodology that is consistent with the project's position. In the event the dispute cannot be resolved through settlement, a trial to determine the level of damages is expected in the second quarter of 2011.

        Energy generated at the Chambers project in excess of amounts delivered to ACE under the Base PPA and to DuPont under the ESA is sold to ACE under a separate power sales agreement (the "PSA"). Under this agreement, energy that ACE does not find economically attractive at the Base PPA's energy rate, but which may be cost effective to sell into the spot market ("Undispatched Energy"), may be self-scheduled by the project to capture additional profits. Margins on Undispatched Energy sales are shared between ACE (40%) and the project (60%). Excess energy not committed to ACE under the Base PPA (above 188 MW in the summer months and 173 MW in the winter months) and not called upon by DuPont under the ESA may also be sold into the market under a similar margin sharing arrangement (30% to ACE and 70% to Chambers). The ESA also provides for the sale by Chambers into the market via annual auctions of capacity not contracted under the Base PPA pursuant to the same margin sharing arrangement (30% to ACE and 70% to Chambers).

        The PSA expired in July 2010 and we entered into a replacement agreement on similar terms that will expire December 31, 2011.

        Some of the steam generated at the Chambers project is sold to DuPont under the ESA, which expires in 2024, but will continue in effect thereafter unless terminated by either party on at least 36 months prior notice. The agreement requires steam to be provided to and budgeted by DuPont up to specified peak steam requirement levels that vary throughout the year. DuPont may purchase steam in excess of the peak steam requirement from any third party, subject to Chambers' right of first refusal to provide steam at the same price. After 2014, DuPont has the option to construct and operate its own steam generation facility for steam volumes in excess of DuPont's take obligations under the ESA, if it can demonstrate that it can generate steam more economically than the project. Chambers has the right to provide steam at an equivalent price as the steam generation project proposed by DuPont. DuPont is required to purchase a minimum quantity of steam necessary for the project to maintain its status as a QF. The steam price is subject to quarterly adjustments based on the price of coal delivered to the project. DuPont has the option in certain circumstances to take over operation of the steam facility in the event of prolonged failure to deliver steam.

        Coal is supplied to the Chambers project pursuant to a coal purchase agreement with Consol Energy Inc. ("Consol"), which expires in 2014 and is subject to a five to ten-year renewal based on good faith negotiations. The agreement governs the sale of coal (including transportation) to the project and the disposal of related ash. Consol is obligated to supply the entire coal requirements for the project, which may include stockpiling. The price escalator under the Base PPA with ACE uses the same index as the coal supply agreement (average coal cost of 25 mid-Atlantic region coal power plants), effectively passing through changes in coal prices to ACE.

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        Operations and maintenance of the Chambers project is performed pursuant to an agreement with Power Plant Management Services, LLC ("PPMS"), which expires in April 2014. Thereafter, the agreement will be automatically renewed for periods of five years until terminated by either party on six months notice. PPMS is paid a base annual fee in addition to cost reimbursement. PPMS is also eligible for performance fees based on facility net availability, efficiency and excess energy optimization, and is eligible for an additional management performance bonus. The majority owner of the project transferred management services from Cogentrix Energy, Inc. to PPMS in December 2010.

        With New Jersey's implementation of the Regional Greenhouse Gas Initiative on January 1, 2009, the Chambers project was required to obtain carbon dioxide ("CO2") allowances in an amount corresponding to the CO2 emissions of the facility. Previously in 2008, the State of New Jersey passed legislation that provided for the sale of CO2 allowances at the price of $2.00 per allowance to certain generating facilities which were certified by the New Jersey Department of Environmental Protection ("NJDEP"). Chambers received this certification from the NJDEP in late 2009. The project maintains the required level of CO2 allowances through a combination of purchases in the quarterly Regional Greenhouse Gas Initiative auctions, broker purchases and purchases from the NJDEP.

        The Chambers project derives a significant portion of its operating margin through capacity revenues received under the Base PPA. In the event the facility does not maintain a minimum level of availability under the Base PPA, the project's capacity payments from ACE would be reduced or eliminated, although it has never experienced such a reduction since commencing operation in 1994. Energy sales under the Base PPA are expected to generate positive margins due to the effective hedging of energy prices and coal costs through the use of identical indexing in the energy payment under the Base PPA and the coal prices under the coal supply contract. While the indexing is identical, adjustments to the energy price under the Base PPA occur annually, whereas coal price adjustments occur quarterly.

        During periods of low spot market electricity prices, energy sales margins may be negatively impacted due to the pricing structure under the Base PPA and PSA. ACE will reduce purchases under the Base PPA to the minimum requirement of 46 MW when the spot electricity price is below the price under the Base PPA. When spot market prices drop below the Base PPA price, but exceed the project's variable production cost, ACE pays for energy based on the PSA, under which a portion of the margin above the project's production cost is shared with ACE. In the unusual situation when the spot electricity price is in excess of the Base PPA but less than the project's variable production cost (which may occur during off-peak periods), Chambers is required to sell energy to ACE at below its production cost. In some cases, the project is further negatively impacted by the facility's reduced fuel efficiency while operating at partial load.


Path 15 segment

        The Path 15 segment consists of our ownership of 72% of the transmission system rights in the Path 15 project, an 84-mile, 500-kilovolt transmission line built along an existing transmission corridor in central California. The Path 15 project commenced commercial operations in 2004. The Path 15 project facilitates the movement of power from the Pacific Northwest to southern California in the summer months and from generators in southern California to northern California in the winter months. The transmission system rights entitle us to receive an annual revenue requirement that is

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regulated by the FERC which established a 30-year regulatory life for the project in connection with its first rate case. The annual revenue requirement is collected from California utilities and remitted to owners of transmission system rights by the California Independent System Operator.

        The Path 15 project and right of way is owned and operated by the Western Area Power Administration, a U.S. Federal power agency that operates and maintains approximately 17,000 miles of transmission lines. The operation of the Path 15 project consists entirely of the transmission of electric power, which is not subject to the same operating risks of a power plant or the volatility that may arise from changes in the price of electricity or fuel.

        The California Independent System Operator ("CAISO") is a not-for-profit corporation that acts as a clearinghouse to settle third-party transactions involving the purchase and sale of power in California. Owners of transmission assets such as Path 15 must place their assets under the operational control of the California Independent System Operator by entering into a standard transmission control agreement with them. In general, the California Independent System Operator coordinates the dispatch of power generation and manages the reliability of, and provides open access to, the transmission grid.

        Three of our wholly-owned subsidiaries have incurred non-recourse debt relating to our interest in the Path 15 project. Total debt outstanding at the Path 15 project as of December 31, 2010 is $153.9 million, which is required to fully amortize over their remaining terms through 2028. See "Project-level debt" on page 72 of this Form 10-K for additional details. We have provided letters of credit totaling $8.0 million to support these debt service obligations.

        The revenue collected by Path 15 is regulated by the FERC on a cost-of-service rate base methodology. Path 15 files a rate case with the FERC every three years to establish its revenue requirement for the next three-year period. The revenue requirement includes all prudently incurred operating costs, depreciation and amortization, taxes, and a return on capital.

        In February 2011, we filed a rate application with the FERC to establish Path 15's revenue requirement for the 2011 - 2013 period. Similar to our rate application filed with the FERC for the three-year period ending 2010, we expect parties to file protests and interventions to become parties to the rate case proceeding. In the event we cannot negotiate a settlement with intervenors, which was accomplished in the last two rate cases, a trial type evidentiary hearing will be held.

        The primary factor influencing the Path 15 project results is its FERC-regulated revenue requirement. Under the FERC's cost-of-service methodology, all prudently incurred expenses are permitted to be recovered in the revenue requirement including costs of the rate case itself every three years. Cash distributions to us could be adversely impacted if the FERC does not continue to approve a return on equity of at least 13.5% in future rate cases.


Other project assets segment

Orlando project

        The Orlando project, a 129 MW natural gas-fired combined-cycle cogeneration facility located in an industrial park near Orlando in Orange County, Florida, commenced commercial operation in 1993 as a QF. We own a 50% interest in the project and Northern Star Generation, LLC ("Northern Star") owns the remaining 50% interest. The project is situated on a four acre site located adjacent to an air separation facility owned by Air Products and Chemicals, Inc. ("Air Products and Chemicals"), which

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serves as the project's steam customer. Orlando sells all of its electricity to PEF and Reedy Creek Improvement District ("Reedy Creek") under long-term PPAs, and also sells chilled water produced using steam from the project to Air Products and Chemicals. The Orlando project typically operates as a baseload plant. Both we and Northern Star have provided letters of credit in the amount of $1.6 million each in support of the project's obligations under the PEF PPA.

        Orlando sells electrical capacity and energy to PEF under a PPA that expires on December 31, 2023. The project is obligated to sell and deliver a committed capacity of 79.2 MW and has committed to a 93% on-peak capacity factor. Orlando receives a monthly capacity payment based on achieving the on-peak capacity factor and a monthly energy payment based on the total amount of electric energy actually delivered to PEF. The capacity payment escalates at 5.1% annually and is reduced if the facility's on-peak capacity factor is below 93%, on a 12-month rolling average basis. Energy payments are comprised of a fuel component based on the cost of coal consumed at two PEF-owned coal-fired generating stations, an operations and maintenance component, a voltage adjustment and an hourly performance adjustment. Off-peak energy prices are based on the on-peak spot market energy price discounted by 10%.

        On August 4, 2009, PEF provided notice to Orlando that the committed capacity under its PPA would be increased to 115 MW upon expiration of the Reedy Creek PPA in 2013, upon meeting certain conditions.

        Orlando sells electrical capacity and energy to Reedy Creek, a municipal district serving the Walt Disney World complex, under a PPA that expires in 2013. Orlando is obligated to sell and deliver 35 MW of electricity and has committed to a 93% average on-peak capacity factor. Orlando receives a monthly capacity payment based on the actual average on-peak capacity factor and a monthly energy payment based on the total amount of electric energy actually delivered to Reedy Creek. The PPA may be extended for an additional ten-year term upon the consent of both parties. The capacity payment is fixed at a rate that escalates at 4.5% annually and is based upon achieving a 93% average on-peak capacity factor, calculated on a three-year rolling average basis. The agreement provides both incentive and penalty provisions for performance above and below a 93% average on-peak capacity factor, respectively. Reedy Creek also reimburses Orlando for a portion of the reservation charges associated with the project's firm gas transportation agreement with Florida Gas. In 2005, Orlando executed an agreement with Reedy Creek for periodic sales of up to 15 MW of non-firm available energy at firm rates.

        In 2006, Orlando executed a master purchase and sale agreement with Rainbow Energy Marketing Corporation ("Rainbow"). Under the agreement, Rainbow markets up to 15 MW of non-firm energy at spot market rates subject to the profitability of such sales. The arrangements with Rainbow can be terminated by either party upon 30 days notice.

        Orlando entered into an agreement with a subsidiary of Air Products and Chemicals to supply chilled water produced using steam from the project to its cryogenic air separation facility. Orlando does not have any minimum steam delivery requirements beyond the thermal and efficiency requirements required to maintain its QF status. Orlando is required to purchase its nitrogen

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requirements from Air Products and Chemicals, but does not have a minimum purchase requirement. Both the purchase price of nitrogen and the sale price of chilled water are at fixed prices that adjust based on the percentage increase/decrease in the producer price index.

        Because of reduced demand for chilled water at Air Products and Chemicals during certain periods, and to ensure continued compliance with QF requirements, Orlando procured and installed water distiller units in 2009, and entered into contracts to provide the distilled water to unaffiliated third parties in the local area.

        Orlando buys natural gas from Orlando Power Holdings, LLC, which is indirectly owned by Northern Star, under an agreement expiring on December 31, 2013. Orlando Power has a back-to-back agreement for the purchase and supply of natural gas from Vastar Gas Marketing, Inc. ("Vastar"), which is a wholly-owned subsidiary of BP Energy Company. Under the agreement, which expires on December 31, 2013, Vastar is obligated to provide Orlando Power with its entire daily natural gas requirement. Orlando's purchase price is tied to the same coal-based and fixed escalators used for calculating the energy payments under the PPAs.

        Affiliates of Orlando Power Holdings, LLC entered into co-terminous back-to-back agreements with Florida Gas for the delivery of natural gas to the project. Orlando has a contractual right to extend these agreements. Transportation costs under the agreements are determined by Florida Gas' rate schedule as filed with the FERC. These agreements provide for the transportation of up to 23,600 Mmbtu per day to the project.

        The Orlando project is operated and maintained by an affiliate of Northern Star under an operations and administrative services agreement expiring on December 31, 2023. The operator is compensated on a cost-reimbursement basis plus a fixed general and administrative charge. In addition, the operator is entitled to receive an incentive fee equal to a percentage of the excess of Orlando's operating cash flow after deducting originally anticipated maintenance capital and anticipated debt service. In 1997, Orlando also entered into a long-term maintenance agreement with Alstom Power Inc. for the long-term supply of hot gas path gas turbine parts, under which Alstom receives a monthly fee from the partnership and additional fees in certain circumstances.

        The Orlando project receives a significant portion of its revenues through capacity payments received under the PPA with PEF. In the event the facility's on-peak capacity factor falls below a specified level, capacity payments will be adjusted downward or eliminated. The energy payment under the PEF PPA largely consists of an energy component, which is adjusted based on the same coal index as used in the gas supply pricing.

        The energy payment under the PPA with PEF includes a performance adjustment. During on-peak periods in which the market price for energy exceeds the PPA energy rate, for energy deliveries in excess of PEF scheduled capacity, the project receives the then as-available energy rate, determined according to regulatory methodology. Conversely, during on-peak periods when the project delivers less than the scheduled capacity, the project incurs negative performance adjustment charges corresponding to the difference between the then as-available energy rate and the PPA energy rate.

        The Reedy Creek PPA also contains incentive and penalty provisions for performance above and below a specified capacity factor.

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Selkirk project

        The Selkirk project is a 345 MW dual-fuel, combined-cycle cogeneration plant located in the Town of Bethlehem in Albany County, New York, which commenced commercial operation in 1994 as a QF. The project includes two units: Unit I (80 MW) currently sells electricity into the New York merchant market and Unit II (265 MW) sells electricity to Consolidated Edison Company of New York, Inc. (or "Con Ed"). The Selkirk project is typically operated as a mid-merit plant. The other partners include affiliates of Cogentrix, Energy Investors Funds, The McNair Group, and Fort Point Power LLC (an affiliate of Osaka Gas Energy America Corporation). Each of the partners has an interest in cash distributions by the project which changes when certain partners achieve a specified return on their equity contributions as set forth in the partnership agreement. We own: (i) 13.62% interest in the priority distributions up to a fixed semi-annual amount as described below; (ii) 19.94% interest on any distributions in excess of the priority distributions; and (iii) 17.7% of all distributions made after the last priority distribution is made, estimated to occur in 2012. If priority distributions are not made at the maximum amount, the unpaid amounts accumulate and are paid when funds are available in subsequent periods. As of December 31, 2010, our 13.62% share of unpaid priority distributions was $1.8 million. In addition to this accumulated amount, our share of the maximum semi-annual priority distributions in 2011 and 2012 is approximately $0.8 million and $0.7 million, respectively. The 15.7 acre project site is situated adjacent to a Saudi Arabia Basic Industries Corporation (or "SABIC") plastics manufacturing plant, which also purchases steam from the project. Selkirk leases the project site under a long-term lease from SABIC.

        The Selkirk project has 8.98% first mortgage bonds outstanding. Our share of the outstanding amount of these bonds was $16.8 million as of December 31, 2010, which fully amortizes over the remaining term ending in 2012. See "Project-level debt" on page 72 of this Form 10-K for additional details.

        Since the expiration of Selkirk's agreement to sell 80 MW of capacity and energy from Unit I to National Grid in July 2008, Selkirk has been selling energy from Unit 1 into the New York merchant market. 265 MW of capacity and energy from Unit II is sold to Con Ed under a PPA that expires on September 1, 2014, subject to a ten-year extension at the option of Con Ed under certain conditions. It is not known whether Con Ed intends to exercise this option. The Unit II PPA provides for a capacity payment, a fuel payment, an operations and maintenance payment and a payment for transmission from the project to Con Ed. The capacity payment, a portion of the fuel payment, a portion of the operations and maintenance payment and the transmission payment are paid on the basis of plant availability.

        Selkirk sells steam generated at the project to the SABIC plastics manufacturing plant under an agreement that expires on September 1, 2014. Under the agreement, SABIC is not charged for steam in an amount up to the annual equivalent of 160,000 lbs/hr during each hour in which the SABIC plant is in production. SABIC pays the project a variable price for steam in excess of this amount. SABIC is required to purchase the minimum thermal output necessary for Selkirk to maintain its QF status.

        Selkirk buys natural gas for Unit I at spot market prices under a contract with Coral Energy Canada Inc. expiring on October 31, 2012. Selkirk has gas supply agreements for Unit II with Imperial

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Oil Resources Limited, EnCana Corporation and Canadian Forest Oil Ltd., which expire on October 31, 2014.

        The project also has long-term contracts for the transportation of Units I and II natural gas volume on a firm 365-day per year basis in place with TransCanada Pipelines Limited, Iroquois Gas Transmission System LP and Tennessee Gas Pipeline Company. The Unit I and Unit II gas transportation contracts expire on November 1, 2012 and November 1, 2014, respectively.

        Natural gas that is not used by Selkirk to generate power under its gas supply arrangements may be remarketed. Units I and II have the capability to operate on fuel oil subject to certain limitations under the project's air permit and are able to switch fuel sources from natural gas to fuel oil and back without interrupting the generation of electricity.

        GE operates the Selkirk project under an agreement expiring on December 31, 2012. The agreement provides for a fixed fee, capital parts discounts, a pass-through of management costs and a performance bonus. Management services for Selkirk are provided by PPMS under an administrative services agreement that expires in September 2014. PPMS is entitled to compensation under the agreement which is subject to renegotiation every four years and provides for the full recovery of its actual costs and properly allocated overhead plus a reasonable fee which must be approved by all of the Selkirk partners. In August 2010, the partners consented to the transfer of management services from Cogentrix to PPMS.

        In 2009, in order to comply with the Regional Greenhouse Gas Initiative, the project commenced purchasing CO2 allowances in the quarterly Regional Greenhouse Gas Initiative auctions. Under the Regional Greenhouse Gas Initiative rules, a compliance period consists of three years, during which time the emitter is required to obtain allowances corresponding to its CO2 emissions during the same period. New York State allocates a limited number of free allowances to generators that have long-term contracts. A portion of the project's annual requirement is met with these free allowances. In resolution of a lawsuit brought by an unaffiliated owner of another New York independent power plant in 2009 challenging New York's Regional Greenhouse Gas Initiative rules, a consent decree was finalized under which Con Ed reimburses the Selkirk project for the cost of additional allowances needed in excess of the free allowances allocated by New York through that term of the PPA.

        Energy produced by Unit I (80 MW) is sold at market prices based on the project's bid into the spot market. The project is therefore exposed to fluctuations in market energy prices which may impact Unit I energy sales margins. Under the PPA with Con Ed, the project receives significant capacity revenues based on meeting availability requirements and also receives an energy payment whenever Con Ed calls on Unit II (265 MW) to generate electricity. The energy payment is primarily dependent on the fuel price component, which is indexed predominantly to natural gas prices, but also has a small component based on oil prices.

        In periods when Unit I or Unit II is not generating electricity, substantial volumes of natural gas are available to be re-sold. Depending on market prices when reselling compared to contract prices when the gas was nominated at the beginning of each month, the excess gas has been resold at significant positive margins and occasionally at a loss.

        TransCanada transports natural gas for the project from Selkirk's suppliers in Empress, Alberta to the interconnection with Iroquois Gas Pipeline in eastern Ontario. Under "cost of service" tolling

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methodology established by the National Energy Board of Canada ("NEB"), TransCanada's tolls are determined by dividing its total annual operating costs by the projected volumes of gas transported. Due to a number of factors, the volumes shipped on TransCanada have decreased significantly over the last few years. In late 2010, TransCanada commenced settlement discussions with its shippers to determine, for the period 2011–2013, the toll for gas transportation from Empress to eastern Canada. Early in the rate making process in December, based on settlement discussions, TransCanada applied for interim tolls that would have represented a reduction from the level in 2010. However after subsequent TransCanada filings, the NEB approved interim tolls that temporarily reflect an increase from the level in 2010. The NEB has instructed TransCanada to submit its final 2011 toll application by May 2011. If TransCanada cannot negotiate a settlement with its major shippers by that time, the NEB will hold hearings to obtain the shipper's arguments and recommendations before it renders a final decision.


Gregory project

        The Gregory project is a 400 MW natural gas-fired combined cycle cogeneration QF located near Corpus Christi, Texas that commenced commercial operation in 2000. The Gregory project is owned by Gregory Power Partners, LP, a Texas limited partnership, and our ownership interest in Gregory Power is approximately 17%. The other owners are affiliates of JP Morgan Chase & Co. and John Hancock Life Insurance Company. Gregory currently sells approximately 345 MW of its capacity to Fortis Energy Marketing and Trading GP ("Fortis") and sells up to 33 MW of electric energy and capacity to Sherwin Alumina Company ("Sherwin"), which is owned by Glencore International AG, with the remainder sold in the spot market. The project is located on a site adjacent to Sherwin's production facility, which also serves as the project's steam customer. Gregory leases the land on which the project is located from Sherwin under an operating lease which expires in August 2035.

        The Gregory project was financed, in part, with a non-recourse debt that matures in 2017 and is required to be amortized over its remaining term. Our share of the total debt outstanding at the Gregory project as of December 31, 2010 was $14.4 million. See "Project-level debt" on page 72 of this Form 10-K for additional details.

        In November 2008, Gregory's managing partner discovered that the state authorization of the project's Prevention of Significant Deterioration Air Permit had lapsed due to a discrepancy in the representation of the renewal date of the state authorization by a consultant in 2002. The issue was self-reported to the Texas Commission of Environmental Quality ("TCEQ"). During the first quarter of 2009, Gregory submitted its initial draft permit application to the TCEQ, which deemed it administratively complete, and completed the technical aspects of the permitting process. In December 2009, TCEQ provided Gregory Power a draft of a new permit, and on March 15, 2010, TCEQ issued the new permit at emissions limits achievable by the project and not requiring the installation of additional emissions control equipment.

        Gregory sells 345 MW of its output to Fortis under a PPA that began on January 1, 2009 and expires December 31, 2013. Under the terms of the Fortis agreement, Fortis pays a fixed capacity payment based on a fixed capacity rate and an energy payment that is based on the price of natural gas at Houston Ship Channel and a contract heat rate. (Heat rate refers to the amount of energy that is required to generate one kilowatt hour of electricity.) Energy sales to Fortis consist of two tranches: a 234 MW "must-run" block and a 111 MW "dispatchable" block. The must-run block corresponds to the project's minimum energy output while satisfying Sherwin's electricity and steam requirements without the use of Gregory's auxiliary boilers. The dispatchable block is the portion of Gregory's output

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that can be scheduled at the option of Fortis as either energy, ancillary services or balancing energy. Credit support for the PPA consists of a $10 million letter of credit issued by ING which is backed by letters of credit from the project's partners, including a $1.7 million letter of credit provided by Atlantic Power.

        Gregory sells steam to Sherwin under an agreement that expires in 2020. Under the terms of the agreement, Gregory is the exclusive source of steam to Sherwin's alumina plant, up to a maximum of 1,500,000 lbs/hr.

        Gregory purchases natural gas under various short-term and long-term agreements. Gregory has the option of procuring 100% of its natural gas requirements from Kinder Morgan Tejas Pipeline, L.P., under a market-based gas supply agreement that expires in August 2012.

        In March and June 2008, the project entered into pay fixed, receive floating, natural gas swap agreements with Sempra Energy Trading Corp. for the period January 2009 through December 2010. While Gregory has structured its power and steam sales agreements to mitigate the price risk between its fuel supply and electricity sales agreements, the project has some residual exposure to natural gas price risk due to the difference between the project's actual heat rate and the contractually guaranteed heat rate under the Fortis PPA. The swap agreements partially mitigated this natural gas price risk.

        An affiliate of Babcock and Wilcox Power Generation Group, Inc. is responsible for the operation and maintenance of the Gregory project under an agreement that terminates in July 14, 2015. The operator receives a fee for management of the facility (subject to escalation) and reimbursement of certain costs.

        Tenaska Power Services, Co. ("Tenaska") provides Gregory with energy management services such as marketing excess power from the Project through the end of 2011. Tenaska optimizes Gregory's assets in the ancillary services market of the Electric Reliability Council of Texas, purchases natural gas for operations, provides scheduling services, provides back-office support and serves as Gregory's retail energy provider and qualified scheduling entity.

        The Gregory project derives a significant portion of its operating margin through energy revenues under its PPA with Fortis. Energy revenues are dependent on the price of natural gas at Houston Ship Channel and a contract heat rate. The project achieves a margin on its energy revenue due to the facility's actual heat rate being lower than the contractually guaranteed heat rate.

        Gregory also receives a capacity payment under the Fortis PPA which is dependent on maintaining certain minimum performance requirements. The project's capacity payments are subject to reduction or elimination if it fails to meet these requirements. Due to a forced outage in 2009, the project only received 98% of the full capacity revenue. However, historically the project has met all of the performance standards under the Fortis PPA.

        Gregory benefits from the heat rate differential between the heat rate of the facility and the contracted heat rate under the terms of the PPA with Fortis. The heat rate of the facility is impacted by the amount of steam that Sherwin is able to accept. If Sherwin's alumina plant were to discontinue

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operations or decrease production levels, it would have adverse impacts on the efficiency of the Gregory facility.


Topsham project

        The Topsham project is a 14 MW hydroelectric facility located on the Androscoggin River at the Pejepscot dam near Topsham, Maine which began commercial operation in 1987 as a QF. A 100% undivided interest in the Topsham project and a 100% undivided interest in the Topsham project site are owned by a financial institution, in its capacity as owner trustee for the benefit of Atlantic Power (50%) and DaimlerChrysler Services North America LLC (50%) as owner participants. Electricity is sold to the Central Maine Power Company ("CMP") under a PPA that expires in 2011.

        The Topsham project is leased and operated by Topsham Hydro Partners Limited Partnership ("THP"), a Minnesota limited partnership. Pursuant to a sale and lease back transaction, THP leases both our interests in the project and in the project site until November 17, 2011. At the end of the lease term, THP has the option to renew the lease or acquire our share of the project and the project site.

        On February 28, 2011, we entered into a purchase and sale agreement with a third party for the purchase of our lessor interest in the project. Closing of the transaction is expected to occur in the second quarter of 2011.

        Electrical output from the Topsham project is sold to CMP under a PPA that contains a fixed price schedule and terminates on December 31, 2011.

        THP operates the project and provides all general and administrative services for the project under an agreement in effect until the earlier of December 31, 2027 or upon THP becoming the owner of 100% of the project and the project site.


Badger Creek project

        The Badger Creek project is a 46 MW simple-cycle, cogeneration facility located near Bakersfield, California which began commercial operation in 1991 as a QF. The Badger Creek project is owned by Badger Creek Limited, L.P. ("Badger"), a Texas limited partnership in which we own a 50% partnership interest. Juniper Generation, LLC, which is indirectly owned by affiliates of ArcLight Capital Partners, LLC, owns the other 50% partnership interest. Electricity is sold to Pacific Gas & Electric Corporation ("PG&E") under a PPA expiring in 2011. The project typically operates in a baseload configuration. Steam is sold to OXY USA Inc. ("OXY"), an affiliate of Occidental Petroleum Corporation, under an agreement that expires in 2011. Badger leases the approximately 3.5 acre site for the Badger Creek project under a ground lease. The term of the lease expires in July 2021 and the parties may extend it for up to 10 additional one-year periods.

        Electricity generated by the Badger Creek project is purchased by PG&E under a PPA that expires in 2011. The PPA provides for monthly capacity and energy payments, and Badger is entitled to receive a performance bonus if the average on-peak capacity factor exceeds 85%. The energy price received

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under the PPA is linked to PG&E's interim "short-run avoided cost," as discussed below. Badger Creek has commenced discussions with PG&E regarding a new PPA. It is expected that these negotiations will not be completed before the expiry of the existing PPA, at which time the project will enter into a one-year interim agreement as provided for under the California Public Utilities Commission ("CPUC") regulations.

        Steam from the Badger Creek project is sold to OXY under an agreement which expires in 2011. The agreement provides for successive renewal terms of one year unless either party gives advance notice of termination. OXY utilizes the steam in its enhanced oil recovery operations to allow for more effective and efficient extraction of heavy crude oil. Subject to certain conditions, OXY has an obligation to buy steam under this agreement in an amount not less than the minimum requirements necessary to maintain the project's status as a QF. Although OXY is not currently purchasing any power from the project, the steam agreement allows for up to 1 MW of electricity to be sold to OXY.

        Natural gas is delivered to Badger Creek via a private pipeline that connects with the Kern River-Mojave Pipeline. The pipeline was constructed by a joint venture in which the project owns approximately 16.8% following the assignment of a portion of the interests in the joint venture in January 2010 to an affiliate of OXY. An affiliate of Juniper operates the pipeline. In October 2006, Badger entered into a gas supply agreement, including transportation, with Sempra Energy Trading Corporation. In March 2008, the gas agreement was extended to cover fuel procurements through April 30, 2011.

        Operations and maintenance for the Badger Creek project is performed by an affiliate of Juniper Generation, LLC under a fixed price operations and maintenance agreement. The agreement expires in April 2011. The operator receives a base monthly fee, which is adjusted annually. In addition, the agreement provides for incentive fees and penalties based on the project's availability. An affiliate of Juniper also provides all day-to-day management services required by the project and is paid a semi-annual fee for such management services based on a percentage of gross cash receipts of the project.

        The Badger Creek project derives a portion of its operating margin through energy revenues under the PG&E PPA. Energy revenues are dependent on PG&E's short-run avoided costs ("SRAC"), which is generally defined as the cost of electricity that a utility avoids incurring by purchasing the power from an independent power producer versus constructing and operating additional generating resources on its own. PG&E's SRAC is determined by the CPUC in conjunction with input from independent power producers, investor owned utilities and consumer groups through the state utility regulatory process. SRAC has been, and continues to be, a highly contested issue resulting in numerous CPUC proceedings and litigation.

        In April 2009, California's Market Reform and Technology Update energy market ("MRTU") commenced operation. The MRTU is expected to provide a robustly traded day-ahead market for energy that reflects the avoided marginal energy costs of California's utilities.

        SRAC was based on an administratively determined formula until August 2009, when the CPUC implemented a new SRAC methodology called the market index formula ("MIF"), which includes both a market-based component and an administratively determined component. Ultimately, the CPUC is

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moving toward a 100% market-based SRAC. Upon the determination by the CPUC that the MRTU is functioning properly, MIF will no longer include the administratively determined component, which is expected to be lower than the original MIF pricing and create larger differences between peak and off-peak prices. Such a determination has not been made by the CPUC.

        Badger has been a party to settlement negotiations among other QF facilities, California's major investor-owned utilities, and numerous consumer and independent power producer groups on a new energy pricing formula and possible extensions of firm capacity payments for projects with existing contracts that will resolve many outstanding issues between the parties. Many of the SRAC and MIF related CPUC proceedings and litigation were held in abeyance pending the outcome of the settlement negotiations. In December 2010, a settlement was approved by the CPUC, however several parties have filed requests for rehearing. The settlement is expected to be finalized and implemented in 2011.

        Badger Creek's PPA and steam sales agreements expire in April 2011. To the extent the agreements cannot be extended or replaced on economical terms, the financial viability of the project would be jeopardized.


Koma Kulshan project

        The Koma Kulshan project is a 13.3 MW run-of-the-river hydroelectric generation facility located on the slopes of Mount Baker, approximately 80 miles north of Seattle, Washington, which began commercial operation in 1990 as a QF. The Koma Kulshan project is owned by Koma Kulshan Associates, a California limited partnership in which we own a 49.75% economic interest, Mt. Baker Corporation owns a 0.25% economic interest and Covanta Energy Corporation ("Covanta") owns the remaining 50%. The Koma Kulshan project was issued a 50-year hydro license from the FERC which expires in 2037. The project and its electrical output is sold to Puget Sound Energy, Inc. under a PPA expiring in 2037.

        Our and Mt. Baker Corporation's interests in the project are held through Concrete Hydro Partners, L.P. ("Concrete"). Under the Concrete partnership agreement, Mt. Baker Corporation is entitled to reimbursement of certain deferred costs associated with the original development of the project from a portion of the distributions from the project. The full repayment of these deferred costs occurred in 2010, following which distributions are projected to be made ratably to us and Mt. Baker Corporation.

        Energy generated by the Koma Kulshan project is sold to Puget Sound Energy pursuant to a long-term PPA expiring in 2037. Power is sold at a per kilowatt hour rate that is adjusted annually. The term of the PPA is co-terminous with the FERC license. Puget Sound Energy has the right to renew the PPA for a term equivalent to the term of any subsequent license or annual license granted by the FERC for the project.

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        Covanta performs the operations and maintenance of the facility pursuant to an operations and maintenance agreement which expires December 31, 2010. In addition to being reimbursed for actual costs incurred, Covanta receives an annual fee adjusted for inflation.


Delta-Person project

        The Delta-Person project, a 132 MW natural gas-fired peaking facility located near Albuquerque, New Mexico, is an exempt wholesale generator that commenced commercial operation in 2000. We own a 40% interest in Delta-Person and affiliates of Olympus Power, LLC, John Hancock Mutual Life Insurance Company, and ArcLight Capital Partners, LLC own the remaining interests. The Delta-Person project is situated on PNM's (formerly Public Service of New Mexico) retired Delta Generating Station site under a lease agreement which is co-terminous with the project's PPA. The project operates as a peaking facility, which means that it is called upon to generate electricity only during unusually high periods of demand. The Delta-Person project sells all of its electrical output to PNM under a long-term PPA that expires in 2020.

        The Delta-Person project was financed with two non-recourse term loans: (i) Tranche A due March 31, 2017; and (ii) Tranche B due March 31, 2019, both of which amortize over their remaining terms. Our share of the total debt outstanding at the Delta-Person project as of December 31, 2010 was $10.5 million. See "Project-level debt" on page 72 of this Form 10-K for additional details.

        Electrical power generated by the Delta-Person project is purchased by PNM under a PPA that will expire in 2020. PNM has the unilateral right to extend the PPA for five years by giving written notice of such extension no later than two years prior to the end of the original term of the PPA. Subject to adjustments provided for in the PPA, PNM will purchase and accept the entire output of the project when PNM calls upon the capacity. Payments consist of: (i) the energy purchase price multiplied by the kilowatt hours delivered; (ii) the capacity purchase price multiplied by the dependable capacity; (iii) the project's cost of purchasing electric service from PNM for the operations and maintenance of the facility; and (iv) any other applicable charges. In order to earn full capacity payments, the project must maintain availability of at least 97%, which the project has historically achieved.

        The project purchases fuel from PNM Gas Services, a division of PNM, with fuel costs passed through to PNM under the PPA. The project has access to an interruptible gas supply and transportation like other standard industrial customers on PNM Gas Services' system.

        As a simple cycle peaking facility, the project operations do not require extensive staffing and technical resources. Olympus Power provides asset management services, which include operational and contractual oversight of the facility, budget setting and environmental compliance. The project has a contractual services agreement in place with GE that covers major maintenance expenses. The costs incurred under this agreement are passed through PNM under the PPA.

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        The Delta-Person project derives a significant portion of its operating margin through capacity payments under the PPA with PNM. The capacity payment is based on two components which adjust annually with changes in inflation and interest rates. The capacity payment may be reduced in any monthif the project's average availability falls below 97% during that month. The project has rarely experienced such adjustment. Energy payments are based on a variable operations and maintenance component, a fuel component and an availability incentive. The fuel component is based on the actual price the project pays for fuel and a contract heat rate. The contractually guaranteed heat rate is slightly higher than the project's average operating heat rate which generates additional energy margin when the project operates. PNM will normally choose to purchase power from higher efficiency plants during periods of reduced demand. Reduced overall economic activity and related lower demand for electricity in the past two years has resulted in lower dispatch of Delta-Person by PNM.


Idaho Wind project

        The Idaho Wind project is a 183 MW wind power project comprised of 11 wind farms located near Twin Falls, Idaho. Construction of the projects began in June 2010 and began commercial operation in 2011 as QFs. The Idaho Wind project is owned by Idaho Wind Partners 1, LLC ("Idaho Wind"), a Delaware limited partnership in which we own a 27.6% partnership interest. Our equity interest in the project was purchased in July 2010. The other owners are affiliates of GE Energy Financial Services, Reunion Power, and Exergy Development Group, the original project developer. Electricity is sold to Idaho Power Company under eleven PPAs expiring in 2030. Idaho Wind leases the land on which the wind projects are located from various land owners under long-term leases that expire in 2040 or after.

        The project was financed by Bank of Tokyo-Mitsubishi and a consortium of other lenders. On October 8, 2010, Idaho Wind closed a $221.7 million project-level credit facility. The facility is composed of two tranches, which include a $138.5 million construction loan that will convert to a 17-year term loan following commercial operation, and an $83.2 million cash grant facility which will be repaid with federal stimulus grant proceeds after completion of construction. On January 20, 2011, Idaho Wind had a second closing for an additional $19.0 million to increase the construction loan to $157.5 million. The construction loan is expected to convert to a term loan in the first quarter of 2011 and will amortize over its life and will mature in 2027.

        The remaining costs of the project of approximately $200 million were funded with a combination of equity from the owners and member loans from affiliates of Atlantic Power and GE Energy Financial Services. As of December 31, 2010, our share of total debt outstanding for Idaho Wind was $48.4 million, and our share of the member loans was $22.8 million. Member loans will be paid down with a combination of excess proceeds from the federal stimulus cash grant after repaying the cash grant facility, funds from a third closing for additional debt, and project cash flow. The federal stimulus grant is expected in the second quarter of 2011 and a third closing is expected by the end of the year. As of March 18, 2011, $5.1 million of the loan has been repaid. See "Project-level debt" on page 72 on this Form 10-K for additional details.

        Idaho Wind sells all of its output to Idaho Power Company under 11 separate 20-year power purchase agreements that expire in 2030. Under the terms of the agreements, Idaho Power purchases all of the electricity at fixed prices, although the pricing structure under the agreements differs. For eight of the eleven PPAs, the fixed price paid for electricity escalates annually through the life of the agreement. For the remaining three agreements, the price paid for electricity remains unchanged for the term of the agreements.

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        In the event the wind farms do not maintain a minimum level of availability or underperform relative to monthly nominations under the PPA, the price paid for electricity would be reduced. The Credit support for the PPAs consists of approximately $20.0 million of letters of credit issued by the project lenders.

        The Idaho Wind project consists of 122 GE 1.5 MW wind turbines purchased under a turbine supply agreement with GE. The turbine supply agreement includes a two-year warranty for removal and replacement of parts.

        Idaho Wind also has an 8-year operations support agreement in place with GE. The operations support agreement provides for ongoing monitoring of the performance of the wind turbine generators as well as planned and unplanned maintenance. The operations support agreement includes a warranty on wind turbine availability. Idaho Wind also has a balance of plant maintenance contract with Caribou Construction, which provides service of the substations and other maintenance not associated with the wind turbines.

        Idaho Wind is operated and maintained on a day-to-day basis by an affiliate of Reunion Power pursuant to a 7-year management service agreement.

        Wind is used to generate electricity utilizing wind turbines to transform the kinetic energy of wind into electrical energy. The Idaho Wind project energy forecast and revenue projections are based on detailed wind studies. Wind speed data were collected on site for over five years then analyzed using complex computer modeling by third party consultants. If there is insufficient wind, the underlying financial performance could be materially adversely affected.

        Idaho Wind is subject to operational risks that could have an adverse effect on financial performance. The risks associated with the project are partially mitigated by the operations support agreement with the original equipment supplier.


Piedmont Green Power project

        Piedmont is a 53.5 MW biomass-fired electric generating facility under construction in Barnesville, Georgia approximately 60 miles southeast of Atlanta. It was developed by our 60% owned subsidiary Rollcast Energy, Inc. The project will sell 100% of its output to Georgia Power Company under a 20-year PPA. Piedmont has executed two long-term biomass fuel supply contracts with pricing terms that largely track the energy payment under the PPA. Zachry Industrial ("ZHI") is constructing the facility under a turn-key engineering procurement and construction contract. The project is being constructed on a 49.8 acre site and will consist of a wood fuel handling system, bubbling fluidized bed boiler technology and a steam turbine generator. Total project costs of approximately $207.4 million were financed in part with an $82.0 million construction loan which will convert to a term loan upon commercial operation, a $51.0 million bridge loan and approximately $75.0 million of equity to be contributed by Atlantic Power. The bridge loan will be repaid from the proceeds of a federal stimulus grant which is expected to be received two months after achieving commercial operation. Notice to proceed was authorized in October 2010 and commercial operation of the project is expected in late 2012.

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        The Project has a twenty-year PPA with Georgia Power for the purchase of capacity and energy expiring in September 2032. The capacity payment rate is seasonally weighted with higher payments in the summer. The capacity payment will be based on the output of the project as demonstrated in performance tests that may be administered annually, if requested by Georgia Power. The capacity payment will be adjusted seasonally based on seasonal plant availability. If contract availability is less than 96% (excluding scheduled maintenance outages, and outages caused by force majeure events) the capacity payment will be reduced by 1.5% for each 1% reduction in availability below 96%. If contract availability is below 60%, no capacity payment will be made. Over 55% of the project's revenue stream consists of capacity payments.

        The energy payment is based on several factors that reflect the cost of acquiring biomass fuel in Georgia. Similar factors are reflected in the pricing of biomass under Piedmont's fuel supply contracts.

        The project has entered into a 10-year interconnection agreement with Southern Company Services. The agreement is subject to automatic renewal for one year periods thereafter. This agreement will provide for the interconnection of the project with the transmission system of Southern Company Services.

        The project's primary source of biomass fuel is urban wood waste provided through long-term supply contracts with two local suppliers. Each contract has minimum take obligations which in aggregate represent 84.0% of Piedmont's total annual biomass fuel requirements. When biomass prices in the spot market are lower than Piedmont's contracted supply, the project will have the ability to take the minimum contract amounts and obtain up to approximately 16% of its annual fuel requirements from the spot biomass market.

        The two fuel supply agreements have terms of 10 and 20 years and each has automatic extension provisions. Pricing under both contracts escalates based on periodic changes in a basket of widely available indices reflecting the cost of obtaining, processing and delivery of urban wood waste biomass. Several biomass fuel studies were prepared in conjunction with the development and financing of the project, which indicated an available and sustainable biomass fuel supply exceeding several times the project's fuel requirements.

        Piedmont has executed a five-year operations and management agreement with Delta Power Services ("DPS"). DPS will be paid its actual direct operating costs plus an annual fee. A portion of the annual fee consists of an operating bonus which is earned by success in five performance metrics based on safety, environmental/emissions compliance, availability, fuel budget and operating budget.

        Piedmont has executed a management services agreement with Rollcast for the provision of administrative services and asset management.

        The Piedmont project is currently under construction and is expected to achieve commercial operation in late 2012. The operation and financial performance of the project may be negatively impacted as a result of circumstances which prevent its timely completion, cause construction costs to exceed the level budgeted, or result in operating performance standards or permit conditions not being met. The terms of the engineering, construction and procurement agreement with ZHI provide for the

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project to be paid significant liquidated damages in the event certain construction milestones or performance testing requirements are not met. These liquidated damages provisions are structured to mitigate the negative impact associated with construction delays or performance shortfalls. Cost overruns are also mitigated by construction contingencies built into the construction budget.

        The Piedmont project will derive a significant portion of its revenue from capacity payments under the Georgia Power PPA. In the event the project does not maintain a high availability factor, these revenues would be adversely impacted.

        The project's results could be reduced due to a divergence in the energy payment under the PPA and the price that Piedmont is paying for fuel, resulting in the project under recovering its fuel expenses. The energy payment under the PPA is based on indices similar to the pricing components in the fuel supply agreements.

        Piedmont is dependent on two fuel suppliers for nearly all of its fuel requirements. In the event either supplier was unable to meet its contractual obligations, the project would need to seek alternative sources for its biomass fuel supply. The project is located in an area of central Georgia, where there are significant and sustainable biomass fuel resources, including urban wood waste, forest residues, and mill residues that are capable of meeting several times the annual fuel requirements of Piedmont.


Cadillac Project

        The Cadillac project is a 39.6 MW biomass power generation facility located in north central Michigan approximately 200 miles north of Detroit. The project achieved commercial operation in July 1993 and is a QF. In December 2010, Atlantic Power acquired a 100% indirect ownership in Cadillac Renewable Energy, LLC, the owner of the project, from Arclight Energy Partners Fund II and Olympus Power, LLC.

        The project is located in Cadillac, Michigan. Cadillac sells up to 34 MW of its capacity and energy under a PPA with Consumers Energy Company ("Consumers"), which expires in 2028, with the remaining output sold in the spot market. The project utilizes approximately 325,000 tons of biomass fuel per year, predominantly derived from the forest products industry in the region. The project is operated by DPS under an operation and maintenance agreement.

        Cadillac has non-recourse debt outstanding of $41.1 million at December 31, 2010, which fully amortizes through 2025. In addition there are notes in the aggregate amount of approximately $1.4 million with Beaver Michigan Associates, LP, a party involved in the early development of the project, due April 15, 2012. We have provided letters of credit of $3.9 million to support the PPA with Consumers.

        Energy and capacity is sold to Consumers pursuant to a PPA that expires on August 1, 2028. Revenues from the sale of electricity consist of a fixed capacity payment and an energy payment. Capacity payments are subject to the project maintaining an availability factor of at least 95% during on-peak hours, on a 12-month calendar year basis. Cadillac is subject to reductions in its capacity payment should it not achieve the 95% availability factor. The project generally has achieved the 95% availability factor continuously since commercial operations began in 1993. Energy payments are comprised of a fixed energy payment and a variable energy payment. The fixed energy payment, paid whether or not the project generates energy, is indexed to several factors related to costs associated with Consumers' costs of generation at established base load coal-fired generating facilities during the most recent calendar year. The variable energy payment is based on the amount of energy delivered to

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Consumers, the average operating costs of certain Consumers base plants during the most recent 12-month period, and the weighted average cost per kWh of coal burned in certain Consumers base plants for the most recent 12-month period.

        In 2007, Cadillac entered into a Reduced Dispatch Agreement ("RDA") with Consumers under which the project shares in the benefit when Consumers reduces the dispatch level of the project to a specified minimum during periods in which it can purchase replacement power in the wholesale market at a price that is less than Cadillac's variable cost of production. Cadillac receives 80% of the net benefits associated with the purchase of displacement power and Consumers receive the remaining 20%. The term of the RDA runs through 2016.

        The project can generate up to 4 MW of power above the maximum 34 MW that is sold to Consumers under the PPA. The excess power is sold into the Michigan Independent System Operator ("ISO"). Cadillac bids the excess power into the Michigan ISO day ahead market when prices exceed its marginal cost of production, plus a minimum gross margin.

        The facility is a qualifying facility under the Michigan Renewable Portfolio Standard ("MRPS") and generates approximately 51,800 MWh of Renewable Energy Credits ("RECs") annually. The RECs are sold into the secondary market.

        The project purchases fuel under numerous short-term supply contracts from approximately 30 local suppliers. The biomass fuel consists of approximately 85% forestry residue. The balance is comprised of sawdust, recycled wood and grindings. The project has annual fuel requirements of approximately 360,000 tons per year, most of which is delivered from within a 75 mile radius of the project.

        The project has a long-term operations and management agreement with DPS that is co-terminous with the PPA in July 2028. Following the acquisition of the project by Atlantic Power, DPS has retained key members of the project's management team, many of whom had been with the project since it began commercial operation 17 years ago.

        As a qualifying facility under the MRPS, the project is reimbursed for a portion of its operating expenses, including fuel, as provided for by Michigan House Bill 5524. The Bill, which does not require annual authorization or appropriation, provides for the reimbursement to qualified facilities of variable operating costs (including fuel) incurred in the production of renewable energy in excess of any variable energy payment received under a PPA. The project receives a monthly payment from Consumers for 80% of the reimbursement. The remaining 20% is withheld for an annual reconciliation. The benefits of House Bill 5524 are limited to seven qualifying facilities in Michigan and payments to the qualifying facilities are capped at $1 million per month. Cadillac's share of the total payments is based on the project's pro rata share of aggregate generation among the six other qualifying facilities. In 2010 the project received $1.5 million under the Bill. Variable costs of operation, including fuel costs in excess of the variable energy payment under the Consumers PPA are eligible for reimbursement.

        A proceeding is currently underway before the Michigan Public Service Commission to, among other things, finalize the reconciliation of reimbursement payments by Consumers for the period of October 2008 through December 2009. A final order from the Michigan Public Service Commission is expected in the second half of 2011.

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Biomass development projects

        Biomass-derived power is a well-established, conventional technology. In biomass power plants, the fuel is burned in a boiler to create steam that turns a turbine to generate electricity. In general, biomass power plants are designed to be operated as baseload units. While biomass encompasses a broad range of potential fuels, our activities are focused on "wood-residue" biomass. This feedstock includes virgin wood (from forests, wood processing facilities, etc.), agricultural residues, industrial and commercial wood waste, etc. These facilities are eligible for renewable energy credits and may also qualify for certain federal tax benefits, depending on their construction schedule. We are pursuing several biomass projects with partners who bring specific skills to their development, as more fully described below.


Rollcast Energy, Inc.

        Rollcast Energy, Inc. ("Rollcast") develops, owns and operates renewable power plants that use wood or biomass fuel. Rollcast, based in Charlotte, North Carolina, has four 50 MW biomass power plants in various stages of development in the southeastern U.S. In March 2009, we acquired a 40% equity interest in Rollcast for $3.0 million. In March 2010, we acquired an additional 15% interest for $1.2 million and in April 2010, we invested an additional $0.8 million to bring our total ownership interest to 60%. The terms of our investment in Rollcast provide us the option, but not the obligation, to invest directly in biomass power plants under development by Rollcast. Two of the development projects have obtained 20-year PPAs with terms that allow for the pass-through of fuel costs to the utility customer. In October 2010, financing closed on one of our Rollcast development projects (Piedmont) and is currently under construction. We have currently invested $68.5 million and expect to invest up to a total of $75.0 million in the Piedmont project, representing substantially all of the equity interests in the project.


Onondaga Renewables, LLC

        Onondaga Renewables, LLC is a 50/50 joint venture between us and Catalyst Renewables LLC formed in December 2008 to repower our decommissioned 91 MW gas-fired cogeneration facility located in Geddes, New York. Utilizing locally acquired biomass fuel, the proposed facility is expected to have a capacity of approximately 45 MW. Onondaga is currently in the process of obtaining a PPA for the full output of the facility. Our share of development expenditures to date is approximately $1.2 million.


ASSET MANAGEMENT

        Our asset management strategy is to ensure that our projects receive appropriate preventative maintenance and capital expenditures if required to provide for their safety, efficiency, availability and longevity. We also proactively look for opportunities to optimize power, fuel supply and other agreements to deliver strong and predictable financial performance. For operations and maintenance services, we partner with recognized leaders in the independent power business. Most of our projects are managed by Caithness; Power Plant Management Services; and, in the case of Path 15, Western, a U.S. Federal power agency. On a case-by-case basis, Caithness, Power Plant Management Services, and Western may provide: (i) day-to-day project-level management, such as operations and maintenance and asset management activities; (ii) partnership level management tasks, such as insurance renewals, annual budgets; and (iii) partnership level management, such as acting as limited partner. In some cases these project managers or the project partnerships may subcontract with other firms experienced in project operations, such as GE, to provide for day-to-day plant operations. In addition, employees of Atlantic Power Corporation with significant experience managing similar assets are involved in all significant decisions with the objective of proactively identifying value-creating opportunities such as

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contract renewals or restructurings, asset-level refinancings, add-on acquisitions, divestitures and attend partnership meetings and calls.

        Caithness is one of the largest privately-held independent power producers in the United States. For over 25 years in the independent power business, Caithness has been actively engaged in the development, acquisition and management of independent power facilities for its own account as well as in venture arrangements with other entities. Caithness operates our Auburndale, Lake and Pasco projects and provides other asset management services for our Orlando, Selkirk and Badger Creek projects.

        Power Plant Management Services is a management services company focused on providing senior level energy industry expertise to the independent power market. Founded in 2006, Power Plant Management provides management services to a large portfolio of solid fuel and gas-fired generating stations. Previously, Cogentrix provided these services to our Selkirk and Chambers facilities. In August 2010, Energy Investors Funds, which holds the controlling interest in a portfolio of 13 power generating projects (of which Chambers and Selkirk are a part), terminated its management services agreement with Cogentrix and entered into a new agreement with Power Plant Management Services.

        Western markets, transmits and delivers hydroelectric power and related services within a 15-state region of the central and western United States. Western is one of four power marketing administrations within the U.S. Department of Energy whose role is to market and transmit electricity from multi-use water projects. Western's transmission system carries electricity from 57 power plants operated by the Bureau of Reclamation, U.S. Army Corps of Engineers and the International Boundary and Water Commission. Together, these plants have an operating capacity of approximately 8,785 MW. Western owns and maintains the Path 15 transmission line.


INDUSTRY REGULATION

Overview

        In the United States, the trend towards restructuring the electric power industry and the introduction of competition in electricity generation began with the passage and implementation of the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). Among other things, PURPA, as implemented by the FERC, generally required that vertically integrated electric utilities purchase power from QFs at their avoided cost. The FERC defines avoided cost as the incremental cost to a utility of energy or capacity which, but for the purchase from QFs, the utility would itself generate or purchase from another source. This requirement was modified in 2005, as discussed below.

        Electric transmission assets, such as our Path 15 project, are regulated by the FERC on a traditional cost-of-service rate base methodology. This approach allows a transmission company to establish a revenue requirement which provides an opportunity to recover operating costs, depreciation and amortization, and a return on capital. The revenue requirement and calculation methodology is reviewed by the FERC in periodic rate cases. As determined by the FERC, all prudently incurred operating and maintenance costs, capital expenditures, debt costs and a return on equity may be collected in rates charged.


Regulation—generating projects

        Ten of our power generating projects are qualifying facilities under PURPA and related FERC regulations. The Delta-Person and Pasco projects are not QFs but are both exempt wholesale generators under the Public Utility Holding Company Act of 2005, as amended ("PUHCA"). The generating projects with QF status and which are currently party to a power purchase agreement with a utility or have been granted authority to charge market-based rates are exempt from FERC rate-making authority. The FERC has granted seven of the projects the authority to charge market-based rates based primarily on a finding that the projects lack market power. These projects are thus

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not subject to FERC rate-making. The generating projects are exempt from regulation under PUHCA and the projects with QF status are also exempt from state regulation respecting the rates of electric utilities and the financial or organizational regulation of electric utilities.

        A QF falls into one or both of two primary classes, both of which would facilitate more efficient use of fossil fuels to generate electricity than typical utility plants. The first class of QFs includes energy producers that generate power using renewable energy sources such as wind, solar, geothermal, hydro, biomass or waste fuels. The second class of QFs includes cogeneration facilities, which must meet specific fossil fuel efficiency requirements by producing both electricity and steam versus electricity only. With the exception of QFs, generation, transmission and distribution of electricity remained largely owned by vertically integrated electric utilities until the enactment of the Energy Policy Act of 1992 (the "EP Act of 1992") and subsequent orders in 1996, along with electric industry restructuring initiated at the state level. Among other things, the EP Act of 1992 enhanced the FERC's power to order open access to power transmission systems, contributing to significant growth in the independent power generation industry.

        In August 2005, the Energy Policy Act of 2005 (the "EP Act of 2005") was enacted, which removed certain regulatory constraints on investment in utility power producers. The EP Act of 2005 also limited the requirement from PURPA that electric utilities buy electricity from QFs to certain markets that lack competitive characteristics. Finally, the EP Act of 2005 amended and expanded the reach of the FERC's corporate merger approval authority under Section 203 of the Federal Power Act.

        All of our projects are subject to reliability standards developed and enforced by the North American Electric Reliability Corporation ("NERC"). NERC is a self-regulatory non-governmental organization which has statutory responsibility to regulate bulk power system users, generation and transmission owners and operators through the adoption and enforcement of standards for fair, ethical and efficient practices.

        In March 2007, the FERC issued an order approving mandatory reliability standards proposed by NERC in response to the August 2003 northeastern U.S. blackouts. As a result, users, owners and operators of the bulk power system can be penalized significantly for failing to comply with the FERC-approved reliability standards. We have designated our Senior Director for Asset Management as our FERC Compliance Officer responsible for meeting the FERC and NERC requirements and an outside law firm specializing in this area advises us on FERC and NERC compliance, including annual compliance training for relevant employees.


Regulation—transmission project

        The revenues received by the Path 15 project are regulated by the FERC through a rate review process every three years that sets an annual revenue requirement. Under terms of the initial rate case settlement, the project must go through the FERC review every three years.

        On February 18, 2011, the project filed its revenue requirement with the FERC for the period of 2011 through 2013. Under the project's prior rate case proceeding at the FERC that set the project's revenue requirement for the period of 2008 through 2010, the Path 15 project was required to file its subsequent rate case no later than February 18, 2011.


Carbon emissions

        In the United States, government policy addressing carbon emissions had gained momentum over the last two years, but has slowed at the federal level more recently. Beginning in 2009, the Regional Greenhouse Gas Initiative was established in ten Northeast and Mid-Atlantic states as the first cap-and-trade program in the United States for CO2 emissions. These states have varied implementation plans and schedules. The two states where we have project interests, New York and New Jersey, also provide cost mitigation for independent power projects with certain types of power

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contracts. Other states and regions in the United Sates are developing similar regulations and it is expected that federal climate legislation will be established in the future.

        Federal bills to create both a cap-and-trade allowance system and a renewable/efficiency portfolio standard have been introduced in both the U.S. House and Senate. Separately, the U.S. Environmental Protection Agency has taken several recent actions to potentially regulate CO2 emissions.

        Additionally, more than half of the U.S. states and most Canadian provinces have set mandates requiring certain levels of renewable energy production and/or energy efficiency during target timeframes. This includes generation from wind, solar and biomass. In order to meet CO2 reduction goals, changes in the generation fuel mix are forecasted to include a reduction in existing coal resources, higher reliance on nuclear, natural gas, and renewable energy resources and an increase in demand-side resources. Investments in new or upgraded transmission lines will be required to move increasing renewable generation from more remote locations to load centers.


COMPETITION

        The power generation industry is characterized by intense competition, and we compete with utilities, industrial companies and other independent power producers. In recent years, there has been increasing competition among generators in an effort to obtain power sales agreements, and this competition has contributed to a reduction in electricity prices in certain markets where supply has surpassed demand plus appropriate reserve margins. In addition, many states and regions have aggressive Demand Side Management programs designed to reduce current load and future local growth.

        The U.S. power industry is continuing to undergo consolidation which may provide attractive acquisition and investment opportunities, although we believe that we will continue to confront significant competition for those opportunities and, to the extent that any opportunities are identified, we may be unable to effect acquisitions or investments on attractive terms.

        We compete for acquisition opportunities with numerous private equity funds, infrastructure funds, Canadian and U.S. independent power firms, utility genco subsidiaries and other strategic and financial players. Our competitive advantages include our competitive access to capital, experienced management team, diversified projects, strong customer base, leading third-party operators and stability of project cash flow. We have similar strength in asset management and optimization.


EMPLOYEES

        As of March 18, 2011, we had 13 employees. None of our employees is represented by any collective bargaining unit or a party to any collective bargaining agreement.

ITEM 1A.    RISK FACTORS

Risks Related to Our Business and Our Projects

Our revenue may be reduced upon the expiration or termination of our power purchase agreements

        Power generated by our projects, in most cases, is sold under PPAs that expire at various times. For example, the PPA at our Badger Creek project expires in 2011 and represent 23 MWs of our net generating capacity. PPAs at our Auburndale, Lake and Gregory projects expire by the end of 2013 and represent 335 MWs of our net generating capacity. The table on page 8 contains details about our projects' PPAs. In addition, these PPAs may be subject to termination in certain circumstances, including default by the project. When a PPA expires or is terminated, it is possible that the price received by the project for power under subsequent arrangements may be reduced significantly. It is possible that subsequent PPAs may not be available at prices that permit the operation of the project

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on a profitable basis. If this occurs, the affected project may temporarily or permanently cease operations.

Our projects depend on their electricity, thermal energy and transmission services customers

        Each of our projects rely on one or more PPAs, steam sales agreements or other agreements with one or more utilities or other customers for a substantial portion of its revenue. The largest customers of our power generation projects, including projects recorded under the equity method of accounting, are Progress Energy Florida, Inc. ("PEF"), Tampa Electric Company ("TECO"), and Atlantic City Electric ("ACE"), which purchase approximately 37%, 14% and 10%, respectively, of the net electric generation capacity of our projects. The amount of cash available to pay dividends to shareholders is highly dependent upon customers under such agreements fulfilling their contractual obligations. There is no assurance that these customers will perform their obligations or make required payments.

Certain of our projects are exposed to fluctuations in the price of electricity

        Those of our projects with no PPA or PPAs based on spot market pricing will be exposed to fluctuations in the wholesale price of electricity. In addition, should any of the long-term PPAs expire or terminate, the relevant project will be required to either negotiate a new PPA or sell into the electricity wholesale market, in which case the prices for electricity will depend on market conditions at the time.

        Our most significant exposure to market power prices is at the Selkirk and Chambers projects. At Chambers, our utility customer has the right to sell a portion of the plant's output into the spot power market if it is economical to do so and the Chambers project shares in the profits from these sales. In addition, during periods of low spot electricity prices the customer takes less generation, which negatively affects the project's profitability. At Selkirk, approximately 23% of the capacity of the facility is not contracted and is sold at market prices or not sold at all if market prices do not support the profitable operation of that portion of the facility.

Our projects may not operate as planned

        The revenue generated by our power generation projects is dependent, in whole or in part, on their availability, performance and the amount of electric energy and steam generated by them. The ability of our projects to meet availability requirements and generate the required amount of power to be sold to customers under the PPAs are primary determinants of the amount of cash that will be distributed from the projects to us, and that will in turn be available for dividends paid to our shareholders. There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, or force majeure events among other things, which could adversely affect revenues and cash flow. To the extent that our projects' equipment requires more frequent and/or longer than forecast down times for maintenance and repair, or suffers disruptions of plant availability and power generation for other reasons, the amount of cash available for dividends may be adversely affected.

        In general, our power generation projects transmit electric power to the transmission grid for purchase under the PPAs through a single step up transformer. As a result, the transformer represents a single point of vulnerability and may exhibit no abnormal behavior in advance of a catastrophic failure that could cause a temporary shutdown of the facility until a replacement transformer can be found or manufactured.

        If the reason for a shutdown is outside of the control of the operator, a power generation project may be able to make a force majeure claim for temporary relief of its obligations under the project contracts such as the PPA, fuel supply, steam sales agreement, or otherwise mitigate impacts through business interruption insurance policies maintenance and debt service reserves. If successful, such insurance claims may prevent a default or reduce monetary losses under such contracts. However, a force majeure claim may be challenged by the contract counterparty and, to the extent the challenge is successful, the outage may still have a materially adverse effect on the project.

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        We provide letters of credit under our senior credit facility for contractual credit support at some of our projects. If the projects fail to perform under the related project-level agreements, the letters of credit could be drawn and the company would be required to reimburse our senior lenders for the amounts drawn.

Our projects depend on suppliers under fuel supply agreements and increases in fuel costs may adversely affect the profitability of the projects

        Revenues earned by our projects may be affected by the availability, or lack of availability, of a stable supply of fuel at reasonable or predictable prices. To the extent possible, the projects attempt to match fuel cost setting mechanisms in supply agreements to energy payment formulas in the PPA. To the extent that fuel costs are not matched well to PPA energy payments, increases in fuel costs may adversely affect the profitability of the projects.

        The amount of energy generated at the projects is highly dependent on suppliers under certain fuel supply agreements fulfilling their contractual obligations. The loss of significant fuel supply agreements or an inability or failure by any supplier to meet its contractual commitments may adversely affect our results.

        Upon the expiration or termination of existing fuel supply agreements, we or our project operators will have to renegotiate these agreements or may need to source fuel from other suppliers. Our project operators may not be able to renegotiate these agreements or enter into new agreements on similar terms. Furthermore, there can be no assurance as to availability of the supply or pricing of fuel under new arrangements and it can be very difficult to accurately predict the future prices of fuel. For example, a portion of the required natural gas at our Auburndale project and all of the natural gas required at our Lake project is purchased at market prices, but the projects' PPAs that expire in 2013 do not effectively pass through changes in natural gas prices. We have executed a hedging program to substantially mitigate this risk through 2013.

        The amount of energy generated at the projects is dependent upon the availability of natural gas, coal, oil or biomass. The long-term availability of such resources could change in the future.

Generation from windpower projects may be less than anticipated

        We now own a windpower project, which is exposed to the risk of its wind resource having unfavorable characteristics, which in conjunction with the wind resource study, could result in unfavorable financial impacts to its expected generation and revenues.

Our operations are subject to the provisions of various energy laws and regulations

        Generally, in the United States, our projects are subject to regulation by the Federal Energy Regulatory Commission, or "FERC," regarding the terms and conditions of wholesale service and rates, as well as by state agencies regarding PPAs entered into by qualifying facility projects and the siting of the generation facilities. The majority of our generation is sold by qualifying facility projects under PPAs that required approval by state authorities.

        In August 2005, the Energy Policy Act of 2005 was enacted, which removed certain regulatory constraints on investment in utility power producers. The Energy Policy Act of 2005 also limited the requirement that electric utilities buy electricity from qualifying facilities to certain markets that lack competitive characteristics, potentially making it more difficult for our current and future projects to negotiate favorable PPAs with these utilities. Finally, the Energy Policy Act of 2005 amended and expanded the reach of the FERC's merger approval authority.

        If any project that is a qualifying facility were to lose its status as a qualifying facility, then such project may no longer be entitled to exemption from provisions of the Public Utility Holding Company Act of 2005 or from provisions of the Federal Power Act and state law and regulations. Such project

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may be able to obtain exempt wholesale generator status to maintain its exemption from the provisions of the Public Utility Holding Company Act of 2005; however, our projects may not be able to obtain such exemptions. Loss of qualifying facility status could trigger defaults under covenants to maintain qualifying facility status in the PPAs and project-level debt agreements and if not cured within allowed cure periods, could result in termination of agreements, penalties or acceleration of indebtedness under such agreements, plus interest.

        Our projects require licenses, permits and approvals which can be in addition to any required environmental permits. No assurance can be provided that we will be able to obtain, comply with and renew, as required, all necessary licenses, permits and approvals for these facilities. If we cannot comply with and renew as required all applicable licenses, permits and approvals, our business, results of operations and financial condition could be adversely affected.

        The Energy Policy Act of 2005 provides incentives for various forms of electric generation technologies, which may subsidize our competitors. In addition, pursuant to the Energy Policy Act of 2005, the FERC selected an electric reliability organization to impose mandatory reliability rules and standards. Among other things, the FERC's rules implementing these provisions allow such reliability organizations to impose sanctions on generators that violate their new reliability rules.

        The introductions of new laws, or other future regulatory developments, may have a material adverse impact on our business, operations or financial condition.

Future FERC rate determinations could negatively impact Path 15's cash flows

        The stability of Path 15's cash flows will continue to be subject to the risk of the FERC's adjusting the expected formulation of revenues upon its rate review every three years. Such a rate review has commenced in February 2011. The cost-of-service methodology currently applied by the FERC is well established and transparent; however, certain inputs in the FERC's determination of rates are subject to its discretion, including its response to protests from intervenors in such rate cases, which include return on equity and the recovery of certain extraordinary expenses. Unfavorable decisions on these matters could adversely affect the cash flow, financial position and results of operations of us and Path 15, and could adversely affect our cash available for dividends.

Noncompliance with federal reliability standards may subject us and our projects to penalties

        Our operations are subject to the regulations of the North American Electric Reliability Corporation ("NERC"), a self-regulatory non-governmental organization which has statutory responsibility to regulate bulk power system users, generation and transmission owners and operators. NERC groups the users, owners, and operators of the bulk power system into 17 categories, known as functional entities—e.g., Generator Owner, Generator Operator, Purchasing-Selling Entity, etc.—according to the tasks they perform. The NERC Compliance Registry lists the entities responsible for complying with the mandatory reliability standards and the FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity found to be in noncompliance. Violations may be discovered through self-certification, compliance audits, spot checking, self-reporting, compliance investigations by NERC (or a regional reliability organization) and the FERC, periodic data submittals, exception reporting, and complaints. The penalty that might be imposed for violating the requirements of the standards is a function of the Violation Risk Factor. Penalties for the most severe violations can reach as high as $1 million per violation, per day, and our projects could be exposed to these penalties if violations occur.

Our projects are subject to significant environmental and other regulations

        Our projects are subject to numerous and significant federal, state and local laws, including statutes, regulations, by-laws, guidelines, policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; ash disposal; the storage, handling,

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use, transportation and distribution of dangerous goods and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the prevention, presence and remediation of hazardous materials in soil and groundwater, both on and off site; land use and zoning matters; and workers' health and safety matters. As such, the operation of our projects carries an inherent risk of environmental, health and safety liabilities (including potential civil actions, compliance or remediation orders, fines and other penalties), and may result in the projects being involved from time to time in administrative and judicial proceedings relating to such matters.

        The Clean Air Act and related regulations and programs of the Environmental Protection Agency extensively regulate the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by power plants. Environmental laws and regulations have generally become more stringent over time, and this trend may continue. In particular, the Environmental Protection Agency has promulgated regulations under the federal Clean Air Interstate Rule ("CAIR") requiring additional reductions in nitrogen oxides, or "NOX," and sulphur dioxide, or "SO2," emissions, beginning in 2009 and 2010 respectively, and has also promulgated regulations requiring reductions in mercury emissions from coal-fired electric generating units, beginning in 2010 with more substantial reductions expected in 2018. Moreover, certain of the states in which we operate have promulgated air pollution control regulations which are more stringent than existing and proposed federal regulations.

        While CAIR was set aside by a court decision in 2008, that decision allowed the CAIR requirements to remain in place pending further rulemaking by the Environmental Protection Agency. On July 6, 2010, the Environmental Protection Agency proposed to replace CAIR with the Interstate Transport Rule which would require 31 states and the District of Columbia to curb emissions of sulfur dioxide and nitrogen oxides from power plants through more aggressive state-by-state emissions budgets for nitrogen oxides and sulfur dioxide. The Environmental Protection Agency expects to finalize the interstate transport rule in late spring of 2011. The first phase of compliance would be required by early 2012 and the second phase by early 2014. Compliance with the proposed rule may have a material adverse impact on our business, operations or financial condition.

        The Environmental Protection Agency proposed new mercury emissions standards for power plants on March 16, 2011 and is expected to have new standards in place by November 2014. Meeting these new standards at our coal-fired facility may have a material adverse impact on our business, operations or financial condition.

        The Resource Conservation and Recovery Act has historically exempted fossil fuel combustion wastes from hazardous waste regulation. However, in June 2010 the Environmental Protection Agency proposed two alternative sets of regulations governing coal ash. One set of proposed regulations would designate coal ash as "special waste" and bring ash impoundments at coal-fired power plants under federal regulations governing hazardous solid waste under Subtitle C of the Resource Conservation and Recovery Act. Another set of proposed regulations would regulate coal ash as a non-hazardous solid waste. If the Environmental Protection Agency determines to regulate coal ash as a hazardous waste, our coal-fired facility may be subject to increased compliance obligations and costs that may have a material adverse impact on our business, operations or financial condition.

        Significant expenditures may be required for either capital expenditures or the purchase of allowances under any or all of these programs to keep the projects compliant with environmental laws and regulations. The projects' PPAs do not allow for the pass through of emissions allowance or emission reduction capital expenditure costs, with the exception of Pasco. If it is not economical to make those expenditures it may be necessary to retire or mothball facilities, or restrict or modify our operations to comply with more stringent standards.

        Our projects have obtained environmental permits and other approvals that are required for their operations. Compliance with applicable environmental laws, regulations, permits and approvals and

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material future changes to them could materially impact our businesses. Although we believe the operations of the projects are currently in material compliance with applicable environmental laws, licenses, permits and other authorizations required for the operation of the projects and although there are environmental monitoring and reporting systems in place with respect to all the projects, there is no guarantee that more stringent laws will not be imposed, that there will not be more stringent enforcement of applicable laws or that such systems may not fail, which may result in material expenditures. Failure by the projects to comply with any environmental, health or safety requirements, or increases in the cost of such compliance, including as a result of unanticipated liabilities or expenditures for investigation, assessment, remediation or prevention, could result in additional expense, capital expenditures, restrictions and delays in the projects' activities, the extent of which cannot be predicted.

Our projects are subject to regulation of CO2 and other greenhouse gases

        Ongoing public concerns about emissions of CO2 and other greenhouse gases have resulted in the enactment of, and proposals for, laws and regulations at the federal, state and regional levels, some of which do or could apply to some of our project operations. For example, the multi-state CO2 cap-and-trade program known as the Regional Greenhouse Gas Initiative applies to our fossil fuel facilities in the Northeast region. The Regional Greenhouse Gas Initiative program went into effect on January 1, 2009. CO2 allowances are now a tradable commodity, currently averaging in the $1.86/ton range. The State of Florida has conducted stakeholder meetings as part of the process of developing greenhouse gas emissions regulations, the most recent of which was in January 2009. Discussions indicate favoring a program similar to that of the Regional Greenhouse Gas Initiative.

        California, New Mexico, Washington and other states are part of the Western Climate Initiative, which is developing a regional cap-and-trade program to reduce greenhouse gas emissions in the region to 15% below 2005 levels by 2020.

        In 2006, the State of California passed legislation initiating two programs to control/reduce the creation of greenhouse gases. The two laws, more commonly known as AB 32 and SB 1368, are currently in the regulatory rulemaking phase which will involve public comment and negotiations over specific provisions. Development towards the implementation of these programs continues.

        Under AB 32 (the California Global Warming Act of 2006) the California Air Resources Board ("CARB") is required to adopt a greenhouse gas emissions cap on all major sources (not limited to the electric sector). In order to do so, it must adopt regulations for the mandatory reporting and verification of greenhouse gas emissions and to reduce state-wide emissions of greenhouse gases to 1990 levels by 2020. This will most likely require that electric generating facilities reduce their emissions of greenhouse gases or pay for the right to emit by the implementation date of January 1, 2012. The program has yet to be finalized and the decision as to whether allocations will be distributed or auctioned will be determined in the rulemaking process that is currently underway. Discussion to date favors an auction-based allocation program.

        Since the 2010 elections in California, the legality of AB 32 has been challenged by several parties. On January 21, 2011, the San Francisco Superior Court issued a proposed decision that could significantly delay the implementation of AB 32. In Association of Irritated Residents, et al. v. California Air Resources Board, Case No. CPF-09-509562, the Court held that the CARB failed to comply with the California Environmental Quality Act. The Court found the CARB to have neglected to conduct a sufficient environmental impact review prior to adopting the AB 32 Scoping Plan. Specifically, CARB failed to adequately analyze all potential alternatives and prematurely adopted the Scoping Plan prior to fully responding to public comment.

        SB 1368 added the requirement that the California Energy Commission, in consultation with the California Public Utilities Commission (the "CPUC") and the CARB establish greenhouse gas emission performance standards and implement regulations for power purchase agreements that exceed five

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years entered into prospectively by publicly-owned electric utilities. The legislation directs the California Energy Commission to establish the performance standard as one not exceeding the rate of greenhouse gas emitted per megawatt-hour associated with combined-cycle, gas turbine baseload generation, such as our Badger Creek project. Provisions are under consideration in the rulemaking process to allow facilities that have higher CO2 emissions to be able to negotiate PPAs for up to a five-year period or sell power to entities not subject to SB 1368.

        In addition to the regional initiatives, legislation for the reduction of greenhouse gases has been introduced at the federal level and if passed, may eventually override the regional efforts with a national cap and trade program. Federal bills to create both a cap-and-trade allowance system and a renewable/efficiency portfolio standard have been introduced in both the House and Senate. Separately, the Environmental Protection Agency has taken several recent actions proposing possible regulation of greenhouse gas emissions.

        The Environmental Protection Agency's actions include its finding of "endangerment" to public health and welfare from greenhouse gases, its issuance in September 2009 of the Final Mandatory Reporting of Greenhouse Gases Rule which requires large sources, including power plants, to monitor and report greenhouse gas emissions to the Environmental Protection Agency annually starting in 2011, and its publication in May 2010 of its final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, to take effect in 2011, which requires large industrial facilities, including power plants, to obtain permits to emit, and to use best available control technology to curb emissions of, greenhouse gases.

        The implementation of existing CO2 and other greenhouse gas legislation or regulation, the introduction of new regulation, or other future regulatory developments may subject the Company to increased compliance obligations and costs that could have a material adverse impact on our business, operations or financial condition.

        All of our generating facilities are prepared to meet the March 31, 2011 requirement to submit 40 CFR Part 98 Mandatory Greenhouse Gas reporting for the emission of eligible site generated greenhouse gases in 2010. This is a national requirement and stands as a start in developing a baseline for greenhouse gases emissions at a national level.

Increasing competition could adversely affect our performance and the performance of our projects

        The power generation industry is characterized by intense competition, and our projects encounter competition from utilities, industrial companies and other independent power producers, in particular with respect to uncontracted output. In recent years, there has been increasing competition among generators for power sales agreements, and this has contributed to a reduction in electricity prices in certain markets where supply has surpassed demand plus appropriate reserve margins. In addition, many states have implemented or are considering regulatory initiatives designed to increase competition in the U.S. power industry. Increasing competition among participants in the power generation industry may adversely affect our performance and the performance of our projects.

We have limited control over management decisions at certain projects

        In a number of cases, our projects are not wholly-owned by us or we have contracted for their operations and maintenance, and in some cases we have limited control over the operation of the projects. Although we generally prefer to acquire projects where we have control, we may make acquisitions in non-control situations to the extent that we consider it advantageous to do so and consistent with regulatory requirements and restrictions, including the Investment Company Act of 1940. Third-party operators (such as Caithness, PPMS and Western) operate many of the projects. As such, we must rely on the technical and management expertise of these third-party operators, although typically we are represented on a management or operating committee if we do not own 100% of a project. To the extent that such third-party operators do not fulfill their obligations to manage the

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operations of the projects or are not effective in doing so, the amount of cash available to pay dividends may be adversely affected.

We may face significant competition for acquisitions and may not successfully integrate acquisitions

        Our business plan includes growth through identifying suitable acquisition opportunities, pursuing such opportunities, consummating acquisitions and effectively integrating them with our business. We may be unable to identify attractive acquisition candidates in the power industry in the future, and we may not be able to make acquisitions on an accretive basis or be sure that acquisitions will be successfully integrated into our existing operations, any of which could negatively impact our ability to continue paying dividends in the future at current rates.

        Although electricity demand is expected to grow, creating the need for more generation, and the U.S. power industry is continuing to undergo consolidation and may offer attractive acquisition opportunities, we are likely to confront significant competition for those opportunities and, to the extent that any opportunities are identified, we may be unable to effect acquisitions or investments.

        Any acquisition or investment may involve potential risks, including an increase in indebtedness, the inability to successfully integrate operations, the potential disruption of our ongoing business, the diversion of management's attention from other business concerns and the possibility that we pay more than the acquired company or interest is worth. There may also be liabilities that we fail to discover, or are unable to discover, in our due diligence prior to the consummation of an acquisition, and we may not be indemnified for some or all these liabilities. In addition, our funding requirements associated with acquisitions and integration costs may reduce the funds available to us to make dividend payments.

Insurance may not be sufficient to cover all losses

        Our business involves significant operating hazards related to the generation of electricity. While we believe that the projects' insurance coverage addresses all material insurable risks, provides coverage that is similar to what would be maintained by a prudent owner/operator of similar facilities, and are subject to deductibles, limits and exclusions which are customary or reasonable given the cost of procuring insurance, current operating conditions and insurance market conditions, there can be no assurance that such insurance will continue to be offered on an economically feasible basis, nor that all events that could give rise to a loss or liability are insurable, nor that the amounts of insurance will at all times be sufficient to cover each and every loss or claim that may occur involving our assets or operations of our projects. Any losses in excess of those covered by insurance, which may include a significant judgment against any project or project operator, the loss of a significant permit or other approval or the imposition of a significant fine or penalty, could have a material adverse effect on our business, financial condition and future prospects and could adversely affect dividends to our shareholders.

Financing arrangements could negatively impact our business

        Our current or future borrowings could increase the level of financial risk to us and, to the extent that the interest rates are not fixed and rise, or that borrowings are refinanced at higher rates, then cash available for dividends could be adversely affected. As of March 18, 2011, we had no borrowings outstanding under our revolving credit facility, $212.9 million of outstanding convertible debentures, and $251.8 million of outstanding non-recourse project-level debt. Covenants in these borrowings may also adversely affect cash available for dividends. In addition, most of the projects currently have non-recourse term loans or other financing arrangements in place with various lenders. These financing arrangements are typically secured by all of the project assets and contracts as well as our equity interests in the project. The terms of these financing arrangements generally impose many covenants and obligations on the part of the borrower. For example, some agreements contain requirements to

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maintain specified debt service coverage ratios before cash may be distributed from the relevant project to us. In many cases, a default by any party under key project agreements (such as a PPA or a fuel supply agreement) will also constitute a default under the project's term loan or other financing arrangement. Failure to comply with the terms of these term loans or other financing arrangements, or events of default thereunder, may prevent cash distributions by the project to us and may entitle the lenders to demand repayment and/or enforce their security interests.

        Our failure to refinance or repay any indebtedness when due could constitute a default under such indebtedness. Under such circumstances, it is expected that dividends to our shareholders would not be permitted until such indebtedness was refinanced or repaid and we may be required to sell assets or take other actions, including the initiation of bankruptcy proceedings or the commencement of an out-of-court debt restructuring.

Our equity interests in our projects may be subject to transfer restrictions

        The partnership or other agreements governing some of the projects may limit a partner's ability to sell its interest. Specifically, these agreements may prohibit any sale, pledge, transfer, assignment or other conveyance of the interest in a project without the consent of the other partners. In some cases, other partners may have rights of first offer or rights of first refusal in the event of a proposed sale or transfer of our interest. These restrictions may limit or prevent us from managing our interests in the projects in the manner we see fit, and may have an adverse effect on our ability to sell our interests in these projects at the prices we desire.

The projects are exposed to risks inherent in the use of derivative instruments

        We and the projects may use derivative instruments, including futures, forwards, options and swaps, to manage commodity and financial market risks. In the future, the project operators could recognize financial losses on these arrangements as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. If actively quoted market prices and pricing information from external sources are not available, the valuation of these contracts would involve judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

        Most of these contracts are recorded at fair value with changes in fair value recorded currently in earnings, resulting in significant volatility in our income (as calculated in accordance with GAAP) that does not significantly affect current period cash flows or the underlying risk management purpose of the derivative instruments. As a result, we may be unable to accurately predict the impact that our risk management decisions may have on our quarterly and annual income (as calculated in accordance with GAAP).

        If the values of these financial contracts change in a manner that we do not anticipate, or if a counterparty fails to perform under a contract, it could harm our financial condition, results of operations and cash flows. We have executed natural gas swaps to reduce our risks to changes in the market price of natural gas, which is the fuel consumed at many of our projects. Due to declining natural gas prices, we have incurred losses on these natural gas swaps. We execute these swaps only for the purpose of managing risks and not for speculative trading.

Our Piedmont project is subject to construction risk

        The Piedmont project commenced construction in November 2010 and is expected to be completed in late 2012. In any construction project, there is a risk that circumstances occur which prevent the timely completion of a project, cause construction costs to exceed the level budgeted, or result in operating performance standards not being met.

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        In the event a power project does not achieve commercial operation by its expected date, the project may be subject to increased construction costs associated with the continuing accrual of interest on the project's construction loan, which customarily matures at the start of commercial operation and converts to a term loan. A delay in completion of construction may also impact a project under its PPA which may include penalty provisions for a delay in commercial operation date or in situations of extreme delay, termination of the PPA.

        Construction cost overruns which exceed the project's construction contingency amount may require that the project owner infuse additional funds in order to complete construction.

        At the completion of construction, the power project may not meet its expected operating performance levels. Adverse circumstances may impact the design, construction, and commissioning of the project that could result in reduced output, increased heat rate or excessive air emissions.


RISKS RELATED TO OUR STRUCTURE

We are dependent on our projects for virtually all cash available for dividends

        We are dependent on the operations and assets of the projects through our indirect ownership of interests in the projects. The actual amount of cash available for dividends to our shareholders depends upon numerous factors, including profitability, changes in revenues, fluctuations in working capital, availability under existing credit facilities, capital expenditure levels, applicable laws, compliance with contracts and contractual restrictive covenants contained in any debt documentation.

Distribution of available cash may restrict our potential growth

        A payout of a significant portion of substantially all of our operating cash flow will make additional capital and operating expenditures dependent on increased cash flow or additional financing in the future. Lack of these funds could limit our future growth and cash flow. In addition, we may be precluded from pursuing otherwise attractive acquisitions or investments if the projected short-term cash flow from the acquisition or investment are not adequate to service the capital raised to fund the acquisition or investment.

Future dividends are not guaranteed

        Dividends to shareholders are paid at the discretion of our board of directors. Future dividends, if any, will depend on, among other things, the results of operations, working capital requirements, financial condition, restrictive covenants, business opportunities, provisions of applicable law and other factors that our board of directors may deem relevant. Our board of directors may decrease the level of or entirely discontinue payment of dividends.

Exchange rate fluctuations may impact the amount of cash available for dividends

        Our payments to shareholders and convertible debenture holders are denominated in Canadian dollars. Conversely, all of our projects' revenues and expenses are denominated in U.S. dollars. As a result, we are exposed to currency exchange rate risks. Despite our hedges against this risk through 2013, any arrangements to mitigate this exchange rate risk may not be sufficient to fully protect against this risk. If hedging transactions do not fully protect against this risk, changes in the currency exchange rate between U.S. and Canadian dollars could adversely affect our cash available for distribution.

Our indebtedness could negatively impact our business and our projects

        The degree to which we are leveraged on a consolidated basis could increase and have important consequences for our shareholders, including:

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        As of March 18, 2011, our consolidated long-term debt and our share of the debt of our unconsolidated affiliates represented approximately 50.3% of our total capitalization, comprised of debt and balance sheet equity.

Changes in our creditworthiness may affect the value of our common shares

        Changes to our perceived creditworthiness may affect the market price or value and the liquidity of our common shares. The interest rate we pay on our credit facility may increase if certain credit ratios deteriorate.

Future issuances of our common shares could result in dilution

        Our articles of incorporation authorize the issuance of an unlimited number of common shares for such consideration and on such terms and conditions as are established by our board of directors without the approval of any of our shareholders. We may issue additional common shares in connection with a future financing or acquisition. The issuance of additional common shares may dilute an investor's investment in us and reduce cash available for distribution per common share.

Investment eligibility

        There can be no assurance that our common shares will continue to be qualified investments under relevant Canadian tax laws for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans, registered education savings plans, registered disability savings plans and tax-free savings accounts.

We are subject to Canadian tax

        As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes, and dividends paid by us are generally subject to Canadian withholding tax if paid to a shareholder that is not a resident of Canada. We completed our initial public offering on the TSX in November 2004. At the time of the initial public offering, our public security was an IPS. Each IPS was comprised of one common share and Cdn$5.767 principal value of 11% subordinated notes due 2016. In the fourth quarter of 2009, we converted to a traditional common share company through a shareholder approved plan of arrangement in which each IPS was exchanged for one of our new common shares. Our new common shares were listed and posted for trading on the TSX commencing on December 2, 2009 and trade under the symbol "ATP," and the former IPSs, which traded under the symbol "ATP.UN," were delisted at that time. In connection with our conversion from an IPS structure to a traditional common share structure and the related reorganization of our organizational structure, we received a note from our primary U.S. holding company (the "Intercompany Note"). We are required to include in computing our taxable income interest on the Intercompany Note. We expect that our existing tax attributes initially will be available to offset this income inclusion such that it will not result in an immediate material increase to our liability for Canadian taxes. However, once we fully utilize our existing tax attributes (or if, for any reason, these attributes were not available to us), our Canadian tax liability would materially increase. Although we intend to explore potential opportunities in the future to preserve the tax efficiency of our structure, no assurances can be given that our Canadian tax liability will not materially increase at that time.

Other Canadian federal income tax risks

        There can be no assurance that Canadian federal income tax laws and Canada Revenue Agency ("CRA") administrative policies respecting the Canadian federal income tax consequences generally

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applicable to us, to our subsidiaries, or to a holder of common shares will not be changed in a manner which adversely affects holders of our common shares.

Our prior and current structure may be subject to additional U.S. federal income tax liability

        Under our prior IPS structure, we treated the subordinated notes as debt for U.S. federal income tax purposes. Accordingly, we deducted the interest payments on the subordinated notes and reduced our net taxable income treated as "effectively connected income" for U.S. federal income tax purposes. Under our current structure, our subsidiaries that are incorporated in the United States are subject to U.S. federal income tax on their income at regular corporate rates (currently as high as 35%, plus state and local taxes), and one of our U.S. holding companies will claim interest deductions with respect to the Intercompany Note in computing its income for U.S. federal income tax purposes. To the extent this interest expense under either the subordinated notes or the Intercompany Note is disallowed or is otherwise not deductible, the U.S. federal income tax liability of our U.S. holding company will increase, which could materially affect the after-tax cash available to distribute to us. While we received advice from our U.S. tax counsel, based on certain representations by us and our U.S. holding company and determinations made by our independent advisors, as applicable, that the subordinated notes and the Intercompany Note should be treated as debt for U.S. federal income tax purposes, it is possible that the Internal Revenue Service ("IRS") could successfully challenge those positions and assert that subordinated notes or the Intercompany Note should be treated as equity rather than debt for U.S. federal income tax purposes. In this case, the otherwise deductible interest on the subordinated notes or the Intercompany Note would be treated as non-deductible distributions and, in the case of the Intercompany Note, would be subject to U.S. withholding tax to the extent our U.S. holding company had current or accumulated earnings and profits. The determination of whether the subordinated notes and the U.S. holding company's indebtedness to us is debt or equity for U.S. federal income tax purposes is based on an analysis of the facts and circumstances. There is no clear statutory definition of debt for U.S. federal income tax purposes, and its characterization is governed by principles developed in case law, which analyzes numerous factors that are intended to identify the nature of the purported creditor's interest in the borrower. Furthermore, not all courts have applied this analysis in the same manner, and some courts have placed more emphasis on certain factors than other courts have. To the extent it were ultimately determined that our interest expense on either the subordinated notes or the Intercompany Note were disallowed, our U.S. federal income tax liability for the applicable open tax years would materially increase, which could materially affect the after-tax cash available to us to distribute. Alternatively, the IRS could argue that the interest on the subordinated notes or the Intercompany Note exceeded or exceeds an arm's length rate, in which case only the portion of the interest expense that does not exceed an arm's length rate may be deductible and, in the case of the Intercompany Note, the remainder would be subject to U.S. withholding tax to the extent our U.S. holding company had current or accumulated earnings and profits. We have received advice from independent advisors that the interest rate on the subordinated notes and the Intercompany Note was and is, as applicable, commercially reasonable in the circumstances, but the advice is not binding on the IRS. Furthermore, our U.S. holding company's deductions attributable to the interest expense on the Intercompany Note may be limited by the amount by which its net interest expense (the interest paid by our U.S. holding company on all debt, including the Intercompany Note, less its interest income) exceeds 50% of its adjusted taxable income (generally, U.S. federal taxable income before net interest expense, net operating loss carryovers, depreciation and amortization). Any disallowed interest expense may currently be carried forward to future years. Moreover, proposed legislation has been introduced, though not enacted, several times in recent years that would further limit the 50% of adjusted taxable income cap described above to 25% of adjusted taxable income, although recent proposals in the Fiscal Year Budget for 2010 would only apply the revised rules to certain foreign corporations that were expatriated. Furthermore, if our U.S. holding company does not make regular interest payments as required under the Intercompany Note, other limitations on the deductibility of interest under U.S.

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federal income tax laws could apply to defer and/or eliminate all or a portion of the interest deduction that our U.S. holding company would otherwise be entitled to with respect to the Intercompany Note.

Passive foreign investment company treatment

        We do not believe that we are a passive foreign investment company, and we do not expect to become a passive foreign investment company. However, if we were a passive foreign investment company while a taxable U.S. holder held common shares, such U.S. holder could be subject to an interest charge on any deferred taxation and the treatment of gain upon the sale of our stock as ordinary income.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None

ITEM 2.    PROPERTIES

        We have included descriptions of the locations and general character of our principal physical operating properties, including an identification of the segments that use such properties, in "Item 1. Business," which is incorporated herein by reference. A significant portion of our equity interests in the entities owning these properties is pledged as collateral under our senior credit facility or under non-recourse operating level debt arrangements. See Note 1 to the consolidated financial statements for additional information regarding our operating properties.

        Our principal executive office is located at 200 Clarendon Street, Floor 25, Boston, Massachusetts under a lease that expires in 2015.

ITEM 3.    LEGAL PROCEEDINGS

        Our Lake project is currently involved in a dispute with Progress Energy Florida over off-peak energy sales in 2010. All amounts billed for off-peak energy during 2010 by the Lake project have been paid in full by Progress. The Lake project has filed a claim against Progress in which we seek to confirm our contractual right to sell off-peak energy at the contractual price for such sales. Progress filed a counter-claim against the Lake project, seeking, among other things, the return of amounts paid for off-peak power sales during 2010 and a declaratory order clarifying Lake's rights and obligations under the PPA. The Lake project has stopped dispatching during off-peak periods and our forward guidance for distributions does not include proceeds from off-peak sales, pending the outcome of the dispute. However, we strongly believe that the court will confirm our contractual right to sell off-peak power using the contractual price that was used during 2010 and that we will be able to continue such off-peak power sales for the remainder of the term of the PPA. We have not recorded any reserves related to this dispute and expect that the outcome will not have a material adverse effect on our financial position or results of operations.

        From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending as of December 31, 2010 that are expected to have a material impact on our financial position or results of operations.

ITEM 4.    (Reserved and Removed)

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information and Holders

        The IPSs were listed and posted for trading on the TSX under the symbol ATP.UN from the time of our initial public offering in November 2004 through November 30, 2009. Following the closing of the exchange of IPSs for common shares, our new common shares commenced trading on the TSX on December 2, 2009 under the symbol ATP. The following table sets forth the price ranges of the outstanding IPSs and common shares, as applicable, as reported by the TSX for the periods indicated:

Period
  High (Cdn$)   Low (Cdn$)  

Quarter ended December 31, 2010

  $ 15.18   $ 13.31  

Quarter ended September 30, 2010

    14.47     12.11  

Quarter ended June 30, 2010

    12.90     11.20  

Quarter ended March 31, 2010

    13.85     11.50  

Quarter ended December 31, 2009

    11.90     9.08  

Quarter ended September 30, 2009

    9.49     8.55  

Quarter ended June 30, 2009

    9.45     7.71  

Quarter ended March 31, 2009

    9.28     6.34  

        Our shares began trading on the NYSE under the symbol "AT" on July 23, 2010. The following table sets forth the price ranges of our outstanding common shares, as reported by the NYSE from the date on which our common shares were listed through December 31, 2010:

Period
  High (US$)   Low (US$)  

Quarter ended December 31, 2010

  $ 14.98   $ 13.26  

July 23, 2010 through September 30, 2010

    14.00     12.10  

        The number of holders of common stock was approximately 46,727 as of March 18, 2011.


Dividends

        Dividends declared per common share in 2010 and 2009 were as follows (Cdn$):

 
  2010   2009  
Month
  Amount  

January

  $ 0.0912   $ 0.0912  

February

    0.0912     0.0912  

March

    0.0912     0.0912  

April

    0.0912     0.0912  

May

    0.0912     0.0912  

June

    0.0912     0.0912  

July

    0.0912     0.0912  

August

    0.0912     0.0912  

September

    0.0912     0.0912  

October

    0.0912     0.0912  

November

    0.0912     0.0912  

December

    0.0912     0.0912  

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Securities Authorized for Issuance under Equity Compensation Plans

 
  Units  

Units authorized

    1,000,000  

Shares issued from long-term incentive plan

    193,678  
       

Remaining units authorized at December 31, 2010

    806,322  
       

ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth our selected historical consolidated financial information for each of the periods indicated. The annual historical information for each of the years in the three-year period ended December 31, 2010 has been derived from our audited consolidated financial statements included elsewhere in this Form 10-K.

        You should read the following selected consolidated financial data along with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the accompanying notes, which are included elsewhere in Form 10-K and which describe the impact of material acquisitions and dispositions that occurred in the three-year period ended December 31, 2010.

 
  Year Ended December 31,  
(in thousands of U.S. dollars, except as otherwise stated)
  2010   2009   2008   2007   2006(a)  

Project revenue

  $ 195,256   $ 179,517   $ 173,812   $ 113,257   $ 69,374  

Project income

    41,879     48,415     41,006     70,118     57,247  

Net (loss) income attributable to Atlantic Power Corporation

    (3,752 )   (38,486 )   48,101     (30,596 )   (2,408 )

Basic earnings per share, US$

  $ (0.06 ) $ (0.63 ) $ 0.78   $ (0.50 ) $ (0.05 )

Basic earnings per share, Cdn$(b)

  $ (0.06 ) $ (0.72 ) $ 0.84   $ (0.53 ) $ (0.06 )

Diluted earnings per share, US$(c)

  $ (0.06 ) $ (0.63 ) $ 0.73   $ (0.50 ) $ (0.05 )

Diluted earnings per share, Cdn$(b)(c)

  $ (0.06 ) $ (0.72 ) $ 0.78   $ (0.53 ) $ (0.06 )

Per IPS distribution declared

  $   $ 0.51   $ 0.60   $ 0.59   $ 0.57  

Per common share dividend declared

  $ 1.06   $ 0.46   $ 0.40   $ 0.40   $ 0.37  

Total assets

  $ 1,013,012   $ 869,576   $ 907,995   $ 880,751   $ 965,121  

Total long-term liabilities

  $ 518,273   $ 402,212   $ 654,499   $ 715,923   $ 613,423  

(a)
Unaudited

(b)
The Cdn$ amounts were converted using the average exchange rates for the applicable periods

(c)
Diluted earnings (loss) per share US$ is computed including dilutive potential shares, which include those issuable upon conversion of convertible debentures and under our long term incentive plan. Because we reported a loss during the years ended December 31, 2010, 2009, 2007 and 2006, the effect of including potentially dilutive shares in the calculation during those periods is anti-dilutive. Please see the notes to our historical consolidated financial statements included elsewhere in this Form 10-K for information relating to the number of shares used in calculating basic and diluted earnings per share for the periods presented.

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ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following management's discussion and analysis of financial condition and results of operations should be read in conjunction with our audited consolidated financial statements included in this Form 10-K. All dollar amounts discussed below are in thousands of U.S. dollars, unless otherwise stated. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").

        This report contains, in addition to historical information, forward-looking statements that involve risks and uncertainties. These forward-looking statements reflect our current views about future events and financial performance. Investors should not rely on forward-looking statements because they are subject to a variety of factors that could cause actual results to differ materially from our expectations. Factors that could cause, or contribute to such differences include, without limitation, the factors described under Item 1A "Risk Factors." In view of these uncertainties, investors are cautioned not to place undue reliance on these forward-looking statements. We assume no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise.


Overview

        Atlantic Power Corporation owns interest in power projects and one transmission line located in the United States. Our current portfolio consists of interests in 13 operational power generation projects across ten states, a 500 kilovolt 84-mile electric transmission line located in California, one biomass project under construction in Georgia and several development stage generating projects. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,962 megawatts ("MW"), in which our ownership interest is approximately 878 MW.

        We sell the capacity and energy from our power generation projects under power purchase agreements (or "PPAs") with a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2011 to 2037, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). We also sell steam from a number of our projects under steam sales agreements to industrial purchasers. The transmission system rights (or "TSRs") we own in our power transmission project entitle us to payments indirectly from the utilities that make use of the transmission line.

        Our power generation projects generally operate pursuant to long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel costs to our customers. In cases where there is not a pass-through of fuel costs, we use a financial hedging strategy designed to mitigate the market price risk of fuel purchases.

        We partner with recognized leaders in the independent power industry to operate and maintain our projects, including Caithness Energy, LLC, Power Plant Management Services and the Western Area Power Administration. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

        We completed our initial public offering on the Toronto Stock Exchange (TSX: ATP) in November 2004. Our shares began trading on the NYSE under the symbol "AT" on July 23, 2010.

        As of March 18, 2011, we had 68,108,042 common shares, Cdn$49.6 million principal amount of 6.50% convertible secured debentures due October 31, 2014 (the "2006 Debentures"), Cdn$76.7 million principal amount of 6.25% convertible debentures due March 15, 2017 (the "2009 Debentures"), and Cdn$80.5 million principal amount of 5.60% convertible debentures due June 30, 2017 (the "2010 Debentures" and together with the 2006 and 2009 Debentures, the "Debentures") outstanding. The

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2006 Debentures, 2009 Debentures and 2010 Debentures are convertible at any time, at the option of the holder, into 80.645, 76.923 and 55.249, respectively, common shares per Cdn$1,000 principal amount of Debentures, representing a conversion price of Cdn$12.40, Cdn$13.00 and Cdn$18.10, respectively, per common share. Holders of common shares currently receive a monthly dividend at a current annual rate of Cdn$1.094 per common share.

        On November 24, 2009, our shareholders approved our conversion from the previous Income Participating Security ("IPS") structure to a traditional common share structure. An IPS was comprised of one common share and Cdn$5.767 principal value of 11% subordinated notes due 2016. Each IPS was exchanged for one new common share and each old common share that did not form part of an IPS was exchanged for approximately 0.44 of a new common share. This transaction resulted in the extinguishment of Cdn$347.8 million ($327.7 million) principal value of 11% subordinated notes due 2016 that previously formed a part of each IPS.


Current Trends in Our Business

        The recession caused significant decreases in both peak electricity demand and consumption that varied by region, although as always, summer and winter peak demand will also be greatly influenced by weather. This has the effect of delaying projected increases in capacity requirements in varying degrees by region. Typically, electricity demand makes a strong recovery to pre-recession levels along with the economic recovery and the projected delays in capacity needs tend to revert to some extent as well, depending on the pace of the recovery. The reduced electricity peak demand and consumption during a recession tends to impact base load (plants that typically operate at all times) and peaking plants (those that only operate in periods of very high demand) more than mid-merit plants (those that operate for a portion of most days, but not at night or in other lower demand periods). During recessionary periods, base load plants may be called on for lower levels of off-peak generation and peaking plants may be called on less frequently as a function of their efficiency and the overall peak demand level. The actual financial impacts on particular plants depend on whether contractual provisions, such as minimum load levels and/or significant capacity payments, partially mitigate the impact of reduced demand. One other recession-related industry impact was an easing of commodity costs, whose previous escalation had greatly increased new plant construction costs. The economic recovery has moved prices higher again for copper, steel and other inputs, with labor costs a function of regional power plant and general construction activity levels, which in some locations includes increased renewable project construction.

        The combination of federal stimulus provisions, state renewable portfolio standards and state or regional CO2/greenhouse gases reduction programs has provided powerful incentives to build new renewable power capacity. One simple impact of this trend is the offsetting reduction in new fossil-fired generation, with the following exception. Because significant renewable capacity is being built as intermittent resources (e.g., wind and solar) there will be an increased need by system operators to have more "firming resources." These are units that can be started quickly or idle at low levels in order to be available to compensate for sudden decreases in output from the solar or wind projects. These firming resources are generally natural gas-fired generators or, in more limited locations, pumped storage or reservoir-based hydro resources. The second significant impact of increased renewable projects is the increased need for new transmission lines to move power from renewable resources in typically more remote locations to the more highly-populated electricity load centers. This transmission requirement will require significant capital and tends to encounter a long and risky development and siting cycle.

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        The substantial additions of economically viable shale gas reserves and increasing production levels have put strong downward pressure on natural gas prices in both the spot and forward markets. One impact of the reduced prices is that gas-fired generators have displaced some generation from base load coal plants, particularly in the southeast U.S. Lower natural gas prices also have compressed, and in some cases turned negative, the "spark spread", which is the industry term for the profit margin between fuel and power prices. Reduced spark spreads directly impact the profitability of plants selling power into the spot market with no contract, which are referred to as merchant plants.

        The lower power prices can have a stifling impact on development of new renewable projects whose owners are attempting to negotiate power purchase agreements at favorable levels to support the financing and construction of the projects. The sense of reduced future volatility of gas prices due to increased supply has reinforced a growing expectation of the role of natural gas as a "bridging fuel," helping from a carbon policy perspective to bridge the desired U.S. transition to both cleaner fuels and more commercially viable carbon removal and sequestration technologies.

        Weak credit markets over the past two years reduced the number of lenders providing power project financing, as well as the size and length of loans, resulting in higher costs for such financing. This reduces the number of new power projects that could be feasibly financed and built. Credit market conditions for project-lending have generally improved, but are still weaker than pre-recession levels. However, base lending rates such as LIBOR have stayed quite low by historical standards, somewhat compensating for the increased interest rate spreads demanded by project lenders. Corporate-level credit markets experienced similar adverse impacts, which impeded the ability of development companies to obtain financing for new power projects.


Factors That May Influence Our Results

        Our primary objective is to generate consistent levels of cash flow to support dividends to our shareholders, which we refer to as "Cash Available for Distribution." Because we believe that our shareholders are primarily focused on income and secondarily on capital appreciation, we provide supplementary cash flow-based non-GAAP information in this Item 7 and discuss our results in terms of these non-GAAP measures, in addition to analysis of our results on a GAAP basis. See "Supplementary Non-GAAP Financial Information" included elsewhere in this Form 10-K for additional details.

        The primary components of our financial results are (i) the financial performance of our projects, (ii) non-cash gains and losses associated with derivative instruments and (iii) interest expense and foreign exchange impacts on corporate-level debt. We have recorded net losses in four of the past five years, primarily as a result of non-cash losses associated with items (ii) and (iii) above, which are described in more detail in the following paragraphs.

        The operating performance of our projects supports cash distributions that are made to us after all operating, maintenance, capital expenditures and debt service requirements are satisfied at the project-level. Our projects are able to generate Cash Available for Distribution because they generally receive revenues from long-term contracts that provide relatively stable cash flows. Risks to the stability of these distributions include the following:

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        In the ordinary course of our business, we execute natural gas swap contracts to manage our exposure to fluctuations in commodity prices, forward foreign currency contracts to manage our exposure to fluctuations in foreign exchange rates and interest rate swaps to manage our exposure to changes in interest rates on variable rate project-level debt. Most of these contracts are recorded at fair value with changes in fair value recorded currently in earnings, resulting in significant volatility in our income that does not significantly affect current period cash flows or the underlying risk management purpose of the derivative instruments. See Item 7A, "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-K for additional details about our derivative instruments.

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        Interest expense relates to both non-recourse project-level debt and corporate-level debt. In addition, in connection with our common share conversion transaction in 2009, we recorded $16.2 million of charges to interest expense associated with the costs of the conversion and the write-off of unamortized debt issuance costs associated with the subordinated notes that were retired. The conversion transaction resulted in Cdn$347.8 million ($327.7 million) of subordinated notes bearing interest at 11% being converted to equity and, as a result, we experienced a significant decrease in our interest expense beginning in 2010. Our convertible debentures are denominated in Canadian dollars and, prior to our common share conversion transaction, the outstanding subordinated notes were also denominated in Canadian dollars. These debt instruments are revalued at each balance sheet date based on the U.S. dollar to Canadian dollar foreign exchange rate at the balance sheet date, with changes in the value of the debt recorded in the consolidated statements of operations. The U.S. dollar to Canadian dollar foreign exchange rate has been volatile in recent years, which in turn creates volatility in our results due to the revaluation of our Canadian dollar-denominated debt.


Outlook

        Based on our actual performance to date and projections for the remainder of the year, we expect to receive distributions from our projects in the range of $80 million to $90 million for the full year 2011. We expect overall levels of operating cash flows in 2011 to be improved over actual 2010 levels. Higher distributions from existing projects, initial distributions from our recent investment in Idaho Wind and Cadillac, and a slightly lower payment under the management termination agreement are expected to be partially offset by the non-recurrence of $8.0 million of cash tax refunds in 2010. In 2012, additional increases in distributions from projects are expected to further increase operating cash flow compared to 2011. The most significant factor in the expected higher operating cash flow in 2012 is increased distributions from Selkirk following the final payment of its non-recourse project-level debt in 2012.

        The following items comprise the most significant increases in projected 2011 project distributions compared to 2010.

        In 2010, the following five projects comprised approximately 90% of project distributions received: Auburndale, Lake, Orlando, Path 15 and Pasco. For 2011, we expect these same five projects to contribute approximately 85% of total project distributions.

        In addition to the items above, the following is a summary of other projections for project distributions in 2011 and beyond:

Lake

        The Lake project is exposed to changes in natural gas prices from the expiration of its natural gas supply contract on June 30, 2009 through to the expiration of its PPA in July 2013 that are not passed through in its PPAs. We have executed a hedging strategy to mitigate this exposure by periodically entering into financial swaps that effectively fix the forward price of natural gas expected to be purchased at the project. These hedges are summarized in Item 7A, "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-K. We intend to continue, when appropriate, to evaluate opportunities to further mitigate natural gas price exposure at Lake in 2013, but do not intend

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to execute additional hedges at Lake for 2011 and 2012 because our natural gas exposure for those years is already substantially hedged.

        The variable energy revenues in the Lake project's PPA are indexed, in part, to the price of coal consumed by a specific utility plant in Florida, the Crystal River facility. The components of this coal price are proprietary to the utility, but we believe that the utility purchases coal for that plant under a combination of short to medium term contracts and spot market transactions.

        Coal prices used in the energy revenue component of the projected distributions from the Lake project incorporate a forecast of the applicable Crystal River facility coal cost provided by the utility based on their internal projections. The projected annual cash distributions change by approximately $1.0 million for every $0.25/Mmbtu change in the projected price of coal.

        We expect to receive distributions from the Lake project of approximately $30 million to $34 million in both 2011 and 2012. The increases in 2011 and 2012 over the $28.8 million of distributions in 2010 are primarily due to higher contractual capacity payments and lower hedged natural gas prices than in 2010.

Auburndale

        Based on the current forecast, we expect distributions from Auburndale of $25 million to $27 million per year from 2011 through 2013, when the project's current PPA expires. Distributions received from Auburndale in the 2011 through 2013 period will be impacted by projected coal and gas prices in the forecast period.

        The projected revenue from the Auburndale PPA contains a component related to the costs of coal consumed at the utility off-taker's Crystal River facility as described above for the Lake project. Because that mechanism does not pass through changes in the project's fuel costs, Auburndale's operating margin is exposed to changes in natural gas prices for approximately 20% of its natural gas requirements through the expiration of the project's gas supply contract. The remaining 80% of the project's fuel requirements are supplied under an agreement with fixed prices through its expiration in mid-2012. We have been executing a strategy to mitigate the future exposure to changes in natural gas prices at Auburndale by periodically entering into financial swaps that effectively fix the forward price of natural gas required at the project. These hedges are summarized in Item 7A, "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-K. The 2011 natural gas price exposure at Auburndale has been substantially hedged. We intend to continue, when appropriate, to evaluate opportunities to further mitigate natural gas price exposure at Auburndale in 2012 and 2013.

Chambers

        As previously reported, reduced cash flows resulted in the project not meeting cash flow coverage ratio tests in its non-recourse debt, so we received no distributions from Chambers in 2009 and in the first nine months of 2010. The Chambers project began to meet the cash flow coverage ratio for its non-recourse debt again as of September 30, 2010 and the project distributed $2.8 million to our project holding company, Epsilon Power Partners in October 2010. However, the required cash flow coverage ratio on the debt at Epsilon Power Partners has not been achieved and, as a result, Epsilon has not made any distributions to the Company during 2009 and 2010. Based on our current projections, Epsilon will continue receiving distributions from the project in 2011 based on meeting the required debt service coverage ratios and we expect Epsilon to resume making distributions to the Company in late 2011.

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Results of Operations

        The following table and discussion is a summary of our consolidated results of operations for the years ended December 31, 2010, 2009 and 2008. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

 
  Year ended December 31,  
(in thousands of U.S. dollars, except as otherwise stated)
  2010   2009   2008  

Project revenue

                   
 

Auburndale

  $ 77,876   $ 74,875   $ 10,003  
 

Lake

    74,024     62,285     61,610  
 

Pasco

    11,305     11,357     58,897  
 

Path 15

    31,000     31,000     31,528  
 

Chambers

             
 

Other Project Assets

    1,051         11,774  
               

    195,256     179,517     173,812  

Project expenses

                   
 

Auburndale

    63,457     59,435     7,669  
 

Lake

    51,694     47,005     39,951  
 

Pasco

    9,594     11,044     48,098  
 

Path 15

    10,748     11,819     10,573  
 

Chambers

    20          
 

Other Project Assets

    1,664     (254 )   41  
               

    137,177     129,049     106,332  

Project other income (expense)

                   
 

Auburndale

    (10,222 )   (4,950 )   (225 )
 

Lake

    (8,721 )   (5,060 )   33  
 

Pasco

    8     25     (4,356 )
 

Path 15

    (12,401 )   (11,682 )   (13,232 )
 

Chambers

    10,289     3,906     11,218  
 

Other Project Assets

    4,847     15,708     (19,912 )
               

    (16,200 )   (2,053 )   (26,474 )

Total project income

                   
 

Auburndale

    4,197     10,490     2,109  
 

Lake

    13,609     10,220     21,692  
 

Pasco

    1,719     338     6,443  
 

Path 15

    7,851     7,499     7,723  
 

Chambers

    10,269     3,906     11,218  
 

Other Project Assets

    4,234     15,962     (8,179 )
               

    41,879     48,415     41,006  

Administrative and other expenses

                   
 

Management fees and administration

    16,149     26,028     10,012  
 

Interest, net

    11,701     55,698     43,275  
 

Foreign exchange loss (gain)

    (1,014 )   20,506     (47,247 )
 

Other (income) expense, net

    (26 )   362     425  
               

Total administrative and other expenses

    26,810     102,594     6,465  
               

Income (loss) from operations before income taxes

    15,069     (54,179 )   34,541  

Income tax expense (benefit)

    18,924     (15,693 )   (13,560 )
               

Net (loss) income

    (3,855 )   (38,486 )   48,101  

Net loss attributable to noncontrolling interest

    (103 )        
               

Net (loss) income attributable to Atlantic Power Corporation shareholders

  $ (3,752 ) $ (38,486 ) $ 48,101  
               

Schedule I-59


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Consolidated Overview

        We have six reportable segments: Auburndale, Lake, Pasco, Path 15, Chambers and Other Project Assets. The results of operations are discussed below by reportable segment.

        Project income is the primary GAAP measure of our operating results and is discussed in "Project Operations Performance" below. In addition, an analysis of non-project expenses impacting our results is set out in "Administrative and Other Expenses (Income)" below.

        Significant non-cash items, which are subject to potentially significant fluctuations, include: (1) the change in fair value of certain derivative financial instruments that are required by GAAP to be revalued at each balance sheet date (see "Quantitative and Qualitative Disclosures About Market Risk" for additional information); (2) the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar-denominated obligations; and (3) the related deferred income tax expense (benefit) associated with these non-cash items.

        Cash available for distribution was $65.5 million, $66.3 million and $91.0 million for the years ended December 31, 2010, 2009 and 2008, respectively. See "Cash Available for Distribution" elsewhere in this Form 10-K for additional information.

        Income (loss) from operations before income taxes for the years ended December 31, 2010, 2009 and 2008 was $15.1 million, $(54.2) million and $34.5 million, respectively. See "Project Income" below for additional information.

Year ended December 31, 2010 compared with Year ended December 31, 2009

Project Income

        The decrease in project income for our Auburndale segment of $6.3 million to $4.2 million in the year ended December 31, 2010 from $10.5 million in 2009 is primarily attributable to the $6.3 million increase in the charge associated with non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 7A, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. Project revenue at Auburndale increased by $3.0 million in 2010 due to favorable energy pricing compared to 2009, as well as the annual contractual escalation of capacity payments. This increased revenue was entirely offset by higher fuel and maintenance costs associated with the hot gas path inspection during 2010.

        Project income for our Lake segment increased $3.4 million to $13.6 million in the year ended December 31, 2010, from $10.2 million in 2009. The increase is primarily attributable to earnings from favorable off-peak dispatch during the summer months as well as the annual escalation of capacity payments, partially offset by higher fuel costs in 2010. In addition, there was a $3.7 million increase in the charge associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 7A, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments.

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        The increase in project income for our Pasco segment of $1.4 million to $1.7 million in the year ended December 31, 2010 from $0.3 million in 2009 is due to lower operations and maintenance expenses attributable to an unplanned outage in 2009.

        Project income for our Path 15 segment increased $0.4 million to $7.9 million in the year ended December 31, 2010 from $7.5 million in 2009 due to lower interest and operations and maintenance expenses in 2010, partially offset by a non-recurring gain in the prior year related to the settlement of disputes with landowners over right-of-way issues.

        Project income for our Chambers segment, which is recorded under the equity method of accounting, increased $6.4 million to $10.3 million in the year ended December 31, 2010 from $3.9 million in 2009. The increase in project income at Chambers is primarily attributable to lower maintenance costs as 2009 maintenance costs included a planned steam turbine overhaul, higher dispatch during a warmer summer in 2010 compared to 2009, and a $1.2 million non-cash change in fair value of derivative instruments associated with its interest rate swaps.

        Project income (loss) for our Other Project Assets segment decreased $11.7 million, to $4.2 million for the year ended December 31, 2010 compared to income of $15.9 million in 2009. The most significant components of the change are as follows:

Administrative and Other Expenses (Income)

        Management fees and administration includes the costs of operating as a public company and, through December 2009, the fees and costs associated with our management by Atlantic Power Management, LLC (the "Manager"). Effective December 31, 2009, the Manager no longer provides management and administrative services for our company. The Manager is indirectly owned by the ArcLight Funds and received compensation in the form of an annual base fee that was indexed to inflation and an incentive fee that was equal to 25% of the cash distributions to shareholders in excess of Cdn$1.00 per year per IPS. We also reimbursed the Manager for reasonable costs incurred to manage our company. Management fees and administration decreased $9.9 million to $16.1 million for the year ended December 31, 2010 from $26.0 million in 2009. The decrease is attributable to the

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$14.1 million charge associated with the termination of the management agreements at the end of 2009 offset by a $2.2 million increase in employee share-based compensation plan expense in 2010. The expense associated with the plan varies, in part, with the market price of our common shares, which increased significantly during the year ended December 31, 2010 compared to the year ended December 31, 2009, resulting in higher expense in 2010. In addition, we incurred $1.0 million of expenses associated with our initial NYSE listing completed in July 2010 and business development costs associated with potential acquisitions.

        Interest expense at the corporate level in 2010 primarily relates to our convertible debentures. Interest expense, net decreased $44.0 million to $11.7 million in 2010 from $55.7 million in 2009. This decrease is primarily due to the extinguishment of the subordinated notes that were outstanding during 2009. In November 2009 we completed our common share conversion, which resulted in the extinguishment of Cdn$347.8 million ($327.7 million) principal value of 11% subordinated notes due 2016 that previously formed a part of each IPS.

        Foreign exchange loss (gain) primarily reflects the unrealized impact of changes in foreign exchange rates on the U.S. dollar equivalent of our Canadian dollar-denominated obligations to holders of the convertible debentures and, through 2009, our subordinated notes. In addition, unrealized and realized gains and losses on our forward contracts for the purchase of Canadian dollars to satisfy these obligations and our dividends to shareholders are included in foreign exchange loss (gain). Unrealized gains and losses on our forward contracts are reclassified to realized gains and losses upon cash settlement of the contracts. Foreign exchange (gain) loss increased $21.5 million to a $1.0 million gain in 2010 compared to a $20.5 million loss in 2009. The U.S. dollar to Canadian dollar exchange rate decreased by 5.7% during the year ended December 31, 2010, compared to a decrease of 15.9% in the comparable period in 2009. See Item 7A "Quantitative and Qualitative Disclosures About Market Risk" for additional details about our management of foreign currency risk and the components of the foreign exchange loss (gain) recognized during the year ended December 31, 2010 compared to the foreign exchange loss (gain) in 2009.

Year ended December 31, 2009 compared with Year ended December 31, 2008

Project Income

        Project income for our Auburndale segment increased $8.4 million to $10.5 million in 2009 from $2.1 million in 2008. The increase in project income for the twelve months ended December 31, 2009 is attributable to the fact that 2009 was the first full year of ownership of the project. The Auburndale project was acquired in November 2008.

        Project income for our Lake segment decreased $11.5 million, or 53%, to $10.2 million in 2009 from $21.7 million in 2008. The decrease is primarily attributable to higher fuel expense at Lake due to the expiration of its natural gas supply agreement as of June 30, 2009. A new gas supply agreement at higher prices was effective for the second half of 2009. In addition, non-cash losses associated with natural gas swaps were recorded in the change in fair value of derivative instruments during 2009 of $5.1 million. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 7A, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments.

Schedule I-62


Table of Contents

        Project income for our Pasco segment decreased $6.1 million, or 95%, to $0.3 million in 2009 from $6.4 million in 2008. The decrease in project income at Pasco was attributable to lower revenues of $47.5 million from the project's new ten-year tolling agreement effective January 1, 2009, which provides for lower rates than the power purchase agreement that expired December 31, 2008, partially offset by lower fuel expense of $26.7 million, since the new agreement requires the utility to provide the natural gas needed to generate electricity at the plant. In addition, depreciation expense decreased by $8.2 million due to the full amortization of the intangible asset associated with the project's PPA that expired on December 31, 2008. The Pasco project also recorded a $3.4 million charge in the change in fair value of derivative instruments in 2008 associated with natural gas swaps that terminated at the end of 2008.

        Project income at Path 15 for the year ended December 31, 2009 did not change significantly from 2008.

        Project income for our Chambers segment, which is recorded under the equity method of accounting, decreased $7.3 million, or 65%, to $3.9 million in 2009 from $11.2 million in 2008 as a result of $9.4 million lower gross margin due to lower electricity sales volumes and prices throughout 2009 and a $4.6 million increase in operation and maintenance costs from a planned major maintenance outage in the second quarter of 2009. In addition, non-cash gains of $2.6 million associated with interest swaps were recorded in the change in fair value of derivative instruments during 2009 compared to $4.3 million of losses in 2008.

        Project income (loss) for our Other Project Assets segment increased $24.1 million, to $15.9 million in 2009 compared to an $(8.2) million loss in 2008, primarily due to the following:

Administrative and Other Expenses (Income)

        Management fees and administration increased $16 million, or 160%, to $26 million in 2009 from $10.0 million in 2008. The increase is primarily attributable to a $14.1 million charge associated with the termination of the management agreements at the end of 2009. In addition, employee and director share-based compensation plan expense increased in 2009. The expense associated with these plans varies, in part, with the market price of our common shares, which increased significantly during 2009 compared to a decrease during the twelve months of 2008, resulting in higher expense in the 2009 period.

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        Interest expense primarily relates to required interest costs associated with the subordinated notes and the debentures. Interest expense, net increased $12.4 million, or 29%, to $55.7 million in 2009 from $43.3 million in 2008. This increase is primarily due to the write-off of unamortized subordinated note deferred finance costs of $7.5 million, the write-off of the unamortized subordinated note premium of $0.9 million and transaction costs of $4.7 million upon closing of our conversion to a common share structure. A charge of $3.1 million was also recorded when we redeemed the remaining subordinated notes in December 2009. This charge was comprised of a premium paid on the redemption of $1.9 million and the write-off of unamortized subordinated note deferred finance costs of $1.2 million. In addition, there were amounts outstanding on our revolving credit facility for a portion of the year ended December 31, 2009 related to the temporary financing of the acquisition of the Auburndale project in late 2008.

        Foreign exchange loss (gain) primarily reflects the unrealized impact of changes in foreign exchange rates on the U.S. dollar equivalent of our Canadian dollar-denominated obligations to holders of subordinated notes and debentures. In addition, unrealized and realized gains and losses on our forward contracts for the purchase of Canadian dollars to satisfy these obligations are included in foreign exchange loss (gain). Foreign exchange loss (gain) increased $67.7 million to a $20.5 million loss in 2009 compared to a $(47.2 million) gain in 2008. The U.S. dollar to Canadian dollar exchange rate decreased by 15.9% during the year ended December 31, 2009. During the year ended December 31, 2008, the rate increased by 18.6%. See Item 7A, "Quantitative and Qualitative Disclosures About Market Risk", below for additional details about our management of foreign currency risk and the components of the foreign exchange loss (gain) recognized during the year ended December 31, 2009 compared to the foreign exchange loss (gain) in 2008.

Supplementary Non-GAAP Financial Information

        The key measure we use to evaluate the results of our projects is Cash Available for Distribution. Cash Available for Distribution is not a measure recognized under GAAP, does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. We believe Cash Available for Distribution is a relevant supplemental measure of our ability to pay dividends to our shareholders. A reconciliation of net cash provided by operating activities to Cash Available for Distribution is set out below under "Cash Available for Distribution." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

        The primary factor influencing Cash Available for Distribution is cash distributions received from the projects. These distributions received are generally funded from Project Adjusted EBITDA generated by the projects, reduced by project-level debt service and capital expenditures, and adjusted for changes in project-level working capital and cash reserves. Project Adjusted EBITDA is defined as project income less interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use unaudited Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. A reconciliation of project income to Project Adjusted EBITDA is set out below under "Project Adjusted EBITDA." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

        Because Project Adjusted EBITDA and project distributions are key drivers of both the performance of our projects and Cash Available for Distribution, please see the following supplementary unaudited non-GAAP information that summarizes Project Adjusted EBITDA by

Schedule I-64


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project and a reconciliation of Project Adjusted EBITDA by project to project distributions actually received by us.


Project Adjusted EBITDA (in thousands of U.S. dollars)

 
  Year ended December 31,  
 
  2010   2009   2008  

Project Adjusted EBITDA by individual segment

                   
 

Auburndale

  $ 34,232   $ 35,221   $ 4,461  
 

Lake

    31,428     25,378     32,892  
 

Pasco

    4,712     3,299     21,953  
 

Path 15

    28,639     27,691     28,872  
 

Chambers

    19,344     13,595     27,603  
               

Total

    118,355     105,184     115,781  

Other Project Assets segment

                   
 

Mid-Georgia

        2,509     4,206  
 

Stockton

        (675 )   1,780  
 

Badger Creek

    3,062     3,245     3,762  
 

Koma Kulshan

    812     822     912  
 

Onondaga

              7,865  
 

Orlando

    7,883     8,858     8,206  
 

Topsham

    1,890     1,879     2,629  
 

Delta-Person

    1,849     894     2,012  
 

Gregory

    4,822     4,482     5,236  
 

Rumford

    (7 )   2,590     2,395  
 

Selkirk

    14,931     15,059     19,104  
 

Rollcast

    (987 )   (234 )    
 

Other

    (26 )   (434 )   801  
               

Total adjusted EBITDA from Other Project Assets segment

    34,229     38,995     58,908  

Project income

                   

Total adjusted EBITDA from all Projects

    152,584     144,179     174,689  

Depreciation and amortization

    65,791     67,643     60,125  

Interest expense, net

    23,628     31,511     30,316  

Change in the fair value of derivative instruments

    17,643     5,047     29,914  

Other (income) expense

    3,643     (8,437 )   13,328  
               

Project income as reported in the statement of operations

  $ 41,879   $ 48,415   $ 41,006  
               

Schedule I-65


Table of Contents


Reconciliation of Project Distributions to EBITDA (in thousands of U.S. dollars)
For the year ended December 31, 2010

 
  Project
Adjusted
EBITDA
  Repayment
of long-
term debt
  Interest
expense,
net
  Capital
expenditures
  Change in
working
capital &
other items
  Project
distribution
received
 

Reportable Segments

                                     
 

Auburndale

  $ 34,232   $ (9,800 ) $ (1,631 ) $ (29 ) $ 4,628   $ 27,400  
 

Chambers

    19,344     (12,052 )   (6,260 )   (42 )   (990 )    
 

Lake

    31,428         9     (1,693 )   (996 )   28,748  
 

Pasco

    4,712         8     (568 )   103     4,255  
 

Path 15

    28,639     (7,480 )   (12,401 )       (819 )   7,939  
                           

Total Reportable Segments

    118,355     (29,332 )   (20,275 )   (2,332 )   1,926     68,342  
                           

Other Project Assets Segment

                                     
 

Badger Creek

    3,062         (15 )       (156 )   2,891  
 

Delta-Person

    1,849     (1,559 )   (274 )       (16 )    
 

Gregory

    4,822     (1,689 )   (296 )   (90 )   (1,325 )   1,422  
 

Koma Kulshan

    812         1     (28 )   179     964  
 

Orlando

    7,883         3     (405 )   (606 )   6,875  
 

Rumford

    (7 )               7      
 

Selkirk

    14,931     (8,863 )   (2,087 )   (79 )   (3,902 )    
 

Topsham

    1,890                 (1 )   1,889  
 

Rollcast

    (987 )       3     (40 )   1,024      
 

Other

    (26 )   (600 )   (688 )   (259 )   2,030     457  
                           

Total Other Project Assets Segment

    34,229     (12,711 )   (3,353 )   (901 )   (2,766 )   14,498  
                           

Total all Segments

  $ 152,584   $ (42,043 ) $ (23,628 ) $ (3,233 ) $ (840 ) $ 82,840  
                           

Schedule I-66


Table of Contents


Reconciliation of Project Distributions to EBITDA (in thousands of U.S. dollars)
For the year ended December 31, 2009

 
  Project
Adjusted
EBITDA
  Repayment
of long-
term debt
  Interest
expense,
net
  Capital
expenditures
  Change in
working
capital &
other items
  Project
distribution
received
 

Reportable Segments

                                     
 

Auburndale

  $ 35,221   $ (3,500 ) $ (2,832 ) $ (322 ) $ 2,419   $ 30,986  
 

Chambers

    13,595     (10,570 )   (7,674 )   (689 )   5,338      
 

Lake

    25,378         4     (1,278 )   (1,405 )   22,699  
 

Pasco

    3,299             (97 )   5,148     8,350  
 

Path 15

    27,691     (7,519 )   (12,912 )       3,798     11,058  
                           

Total Reportable Segments

    105,184     (21,589 )   (23,414 )   (2,386 )   15,298     73,093  
                           

Other Project Assets Segment

                                     
 

Mid-Georgia

    2,509     (1,694 )   (3,271 )   11     2,445      
 

Stockton

    (675 )       (70 )   (297 )   1,042      
 

Badger Creek

    3,245         (17 )       447     3,675  
 

Delta-Person

    894     (1,512 )   (224 )       842      
 

Gregory

    4,482     (2,903 )   (1,792 )   (98 )   2,551     2,240  
 

Koma Kulshan

    822         1     (79 )   (553 )   191  
 

Orlando

    8,858         14     (632 )   4,435     12,675  
 

Rumford

    2,590         2         309     2,901  
 

Selkirk

    15,059     (8,122 )   (2,777 )   161     (1,325 )   2,996  
 

Topsham

    1,879     (45 )   (2 )           1,832  
 

Other

    (668 )       39     (62 )   1,248     557  
                           

Total Other Project Assets Segment

    38,995     (14,276 )   (8,097 )   (996 )   11,441     27,067  
                           

Total all Segments

  $ 144,179   $ (35,865 ) $ (31,511 ) $ (3,382 ) $ 26,739   $ 100,160  
                           

Schedule I-67


Table of Contents


Reconciliation of Project Distributions to EBITDA (in thousands of U.S. dollars)
For the year ended December 31, 2008

 
  Project
Adjusted
EBITDA
  Repayment
of long-
term debt
  Interest
expense,
net
  Capital
expenditures
  Change in
working
capital &
other items
  Project
distribution
received
 

Reportable Segments

                                     
 

Auburndale

  $ 4,461   $   $ (225 ) $   $ 1,764   $ 6,000  
 

Chambers

    27,603     (9,639 )   (8,537 )   (145 )   1,414     10,696  
 

Lake

    32,892         33     (814 )   (931 )   31,180  
 

Pasco

    21,953     (12,038 )   (978 )   (175 )   10,883     19,645  
 

Path 15

    28,872     (8,086 )   (13,232 )       156     7,710  
                           

Total Reportable Segments

    115,781     (29,763 )   (22,939 )   (1,134 )   13,286     75,231  
                           

Other Project Assets Segment

                                     
 

Mid-Georgia

    4,206     (2,646 )   (3,271 )   11     1,700      
 

Stockton

    1,780         (9 )   (61 )   (1,460 )   250  
 

Badger Creek

    3,762         (3 )       441     4,200  
 

Delta-Person

    2,012     (1,027 )   (738 )       (247 )    
 

Gregory

    5,236     (1,807 )   288     (133 )   6,827     10,411  
 

Koma Kulshan

    912         4     (192 )   (528 )   196  
 

Onondaga

    7,865         81     (3 )   11,693     19,636  
 

Orlando

    8,206     (3,468 )   16     (306 )   (1,048 )   3,400  
 

Rumford

    2,395         2     (187 )   524     2,734  
 

Selkirk

    19,104     (6,915 )   (3,403 )   (60 )   (695 )   8,031  
 

Topsham

    2,629     (2,400 )   (193 )       (36 )    
 

Other

    801         (151 )   (113 )   (137 )   400  
                           

Total Other Project Assets Segment

    58,908     (18,263 )   (7,377 )   (1,044 )   17,034     49,258  
                           

Total all Segments

  $ 174,689   $ (48,026 ) $ (30,316 ) $ (2,178 ) $ 30,320   $ 124,489  
                           

Project Operations Performance—Year ended December 31, 2010 compared with Year ended December 31, 2009

        Aggregate Project Adjusted EBITDA increased $8.4 million to $152.6 million in the year ended December 31, 2010 from $144.2 million in 2009 and included the following factors:

Schedule I-68


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        Aggregate power generation for projects in operation at December 31, 2010 was 2.5% less than the year ended December 31, 2009. Generation during the year ended December 31, 2010 compared to the prior year was favorably impacted primarily by increased generation at Lake associated with dispatch during off-peak hours due to favorable market conditions, Chambers due to higher dispatch also as a result of favorable market conditions. The favorable variance was offset by the absence of Stockton and Mid-Georgia generation as the projects were sold in the fourth quarter of 2009 and by lower Phase II dispatch at Selkirk.

        The project portfolio achieved a weighted average availability of 95.3% for the year ended December 31, 2010 compared to 95.1% in the 2009 period. The increase in portfolio availability for the year ended December 31, 2010 was primarily due to planned and forced outages at Chambers and Badger, respectively, in 2009 offset by planned outages at Lake and Auburndale in 2010. Each of the projects with reduced availability was nevertheless able to achieve substantially all of their respective capacity payments as a result of contract terms that provide for certain levels of planned and unplanned outages.

Project Operations Performance—Year ended December 31, 2009 compared with Year ended December 31, 2008

        Aggregate Project Adjusted EBITDA for the segments decreased $30.5 million, or 17%, to $144.2 million in 2009 from $174.7 million in 2008 and included the following factors:

Aggregate power generation for projects in operation at December 31, 2009 was 2.6% lower during 2009 as compared to 2008. Weighted average plant availability increased 1.1% over the same period. Generation during the twelve months of 2009 versus the prior year period was unfavorably impacted primarily by reduced dispatch at Chambers. This was due to low market prices and a planned major maintenance outage, offset by the acquisition of Auburndale in November 2008. Also contributing to the lower generation during the period was reduced generation at Pasco as a result of the expected lower dispatch under the new tolling agreement that went into effect on January 1, 2009, which was partially offset by increased generation at Orlando in 2009 due to its unscheduled outage in March 2008.

Schedule I-69


Table of Contents

        The project portfolio achieved a weighted average availability of 94.5% for 2009 versus 93.4% in 2008. The higher portfolio availability was primarily driven by the increased availability of Orlando versus the prior period resulting from the March 2008 unplanned outage as well as higher availability at Mid-Georgia due to a scheduled outage in April 2008, and the acquisition of Auburndale in November 2008, offset slightly by reduced availability at Chambers associated with a longer planned outage versus the prior period. Each of the projects with reduced availability was nevertheless able to achieve substantially all of its respective capacity payments as a result of contract terms that provide for certain levels of planned and unplanned outages.


Cash Flow from Operating Activities

        Our cash flow from the projects may vary from year to year based on, among other things, changes in prices under the PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, changes in regulated transmission rates, compliance with the terms of non-recourse project-level financing including debt repayment schedules, the transition to market or recontracted pricing following the expiration of PPAs, fuel supply and transportation contracts, working capital requirements and the operating performance of the projects. Project cash flows may have some seasonality and the pattern and frequency of distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.

        Cash flow from operating activities increased by $36.5 million for the year ended December 31, 2010 over the comparable period in 2009. The change from the prior year is primarily attributable to a significant decrease in cash interest expense as a result of our common share conversion in November 2009, which eliminated Cdn$347.8 million ($327.7 million) of outstanding subordinated notes, as well as higher net cash tax refunds of $8.0 million. The positive change in operating cash flow attributable to the reduced interest expense was partially offset by a $5.8 million decrease in distributions from our Orlando project and no distributions in 2010 from our Selkirk project, both of which are equity method investments. The decrease in distributions from Orlando was the result of a one-time receipt of insurance proceeds in 2009 related to an unplanned outage that occurred in 2008. The Selkirk project is currently not making distributions to partners as a result of restrictions in its non-recourse project-level debt. We expect to resume receiving distributions from Selkirk in late 2011 or early 2012.

        Cash flow from operating activities decreased by $27.3 million for the year ended December 31, 2009 as compared to 2008. The changes from the prior period are consistent with and primarily attributable to the changes in Project Adjusted EBITDA described above. In addition, the $6.0 million payment in December 2009 under the terms of the management agreement termination reduced operating cash flow for the twelve months ended December 31, 2009.


Cash Flow from Investing Activities

        Cash flow from investing activities includes restricted cash. Restricted cash fluctuates from period to period in part because non-recourse project-level financing arrangements typically require all operating cash flow from the project to be deposited in restricted accounts and then released at the time that principal payments are made and project-level debt service coverage ratios are met. As a result, the timing of principal payments on project-level debt causes significant fluctuations in restricted cash balances, which typically benefits investing cash flow in the second and fourth quarters of the year and decreases investing cash flow in the first and third quarters of the year.

        Cash flows used in investing activities for the year ended December 31, 2010 were $147.0 million compared to cash flows provided by investing activities of $25.0 million for the year ended December 31, 2009. We acquired a 27.6% equity interest in Idaho Wind for $38.9 million and approximately $3.1 million in transaction costs. In addition, we loaned $22.8 million to Idaho Wind to temporarily fund a portion of construction costs at the project. We acquired 100% interest of Cadillac Renewable Energy for $36.6 million and assumed $43.1 million in non-recourse project-level debt. We invested $47.7 million for the construction-in-progress for our Piedmont biomass project.

Schedule I-70


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        Cash flows provided by investing activities for the year ended December 31, 2009 were $25.0 million compared to cash flows used in investing activities of $128.6 million for the year ended December 31, 2008. We sold the assets of Mid Georgia in 2009 for proceeds of $29.1 million compared to no asset sales in 2008. In addition, we acquired Auburndale in 2008 for a total purchase price of $141.7 million compared to no acquisitions in 2009.


Cash Flow from Financing Activities

        Cash provided by financing activities for the year ended December 31, 2010 resulted in a net inflow of $55.7 million compared to a net outflow of $62.9 million for the same period in 2009. The change from the prior year is primarily attributable to $72.8 million in net proceeds from our equity offering and $74.6 million in net proceeds from the issuance of convertible debentures, offset by a $40.0 million increase in dividends paid and a $6.1 million increase in project-level debt payments. We completed our common share conversion in November 2009. As a result, Cdn$347.8 million ($327.7 million) of subordinated notes were extinguished and our entire monthly distribution to shareholders is now paid in the form of a dividend as opposed to the monthly distribution being split between a subordinated notes interest payment and a common share dividend during the year ended December 31, 2009.

        Cash used in financing activities for the year ended December 31, 2009 resulted in a net outflow of $62.9 million compared to a net inflow of $38.4 million for the same period in 2008. Our significant cash flows from our 2009 and 2008 financing transactions are described below:


Cash Available for Distribution

        Prior to our conversion to a common share structure, holders of our IPSs received monthly cash distributions in the form of interest payments on subordinated notes and dividends on common shares. Subsequent to the conversion, holders of common shares receive the same monthly cash distributions of Cdn$1.094 per year in the form of a dividend on the new common shares. The payout ratio for the year ended December 31, 2010 was 100%.

Schedule I-71


Table of Contents

        The table below presents our calculation of cash available for distribution for the years ended December 31, 2010, 2009 and 2008:

 
  Year ended December 31,  
(unaudited)
(in thousands of U.S. dollars, except as otherwise stated)
  2010   2009   2008  

Cash flows from operating activities

  $ 86,953   $ 50,449   $ 77,788  

Project-level debt repayments

    (18,882 )   (12,744 )   (22,275 )

Interest on IPS portion of subordinated notes(1)

        30,639     36,560  

Purchases of property, plant and equipment(2)

    (2,549 )   (2,016 )   (1,102 )
               

Cash Available for Distribution(3)

    65,522     66,328     90,971  

Interest on subordinated notes

   
   
30,639
   
36,560
 

Dividends on common shares

    65,648     27,988     24,692  
               

Total distributions to shareholders

  $ 65,648   $ 58,627   $ 61,252  
               

Payout ratio

   
100

%
 
88

%
 
67

%

Expressed in Cdn$

                   

Cash Available for Distribution

    67,540     75,673     97,102  

Total common share distributions

   
67,914
   
66,325
   
65,143
 

(1)
Prior to the common share conversion in November 2009, a portion of our monthly distribution to IPS holders was paid in the form of interest on the subordinated notes comprising a part of the IPSs. Subsequent to the conversion, the entire monthly cash distribution is paid in the form of a dividend on our common shares.

(2)
Excludes construction-in-progress costs related to our Piedmont biomass project.

(3)
Cash Available for Distribution is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP. Therefore, this measure may not be comparable to similar measures presented by other companies. See "Supplementary Non-GAAP Financial Information" above.


Liquidity and Capital Resources

Overview

        Our primary source of liquidity is distributions from our projects and availability under our revolving credit facility. A significant portion of the cash received from project distributions is used to pay dividends to our shareholders and interest on our outstanding convertible debentures. We may fund future acquisitions with a combination of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately-placed bank or institutional non-recourse operating level debt.

        We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due.

        With the exception of our commitment to the construction of Piedmont Green Power, we do not expect any material unusual requirements for cash outflows for 2011 for capital expenditures or other required investments. We expect to contribute approximately $75.0 million to fund the equity portion of the construction costs for Piedmont. Approximately $59.0 million of this amount has been contributed in the fourth quarter of 2010, with the remaining balance to be paid in the first quarter of 2011. In addition, there are no debt instruments with significant maturities or refinancing requirements in 2011.

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See "Outlook" above for information about changes in expected distributions from our projects in 2011 and beyond.

Credit facility

        We maintain a credit facility with a capacity of $100 million, $50 million of which may be utilized for letters of credit. The credit facility matures in August 2012.

        The credit facility bears interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin between 1.5% and 3.25% that varies based on the credit statistics of one of our subsidiaries. As of December 31, 2010, the applicable margin was 1.5%. As of December 31, 2010, $48.6 million was allocated, but not drawn, to support letters of credit for contractual credit support at eight of our projects. In June 2010, we borrowed $20 million under the credit facility and used the proceeds to partially fund the acquisition of Idaho Wind in July 2010. In October 2010, we repaid the $20 million borrowing with proceeds from our common stock and convertible debt offerings.

        We must meet certain financial covenants under the terms of the credit facility, which are generally based on the cash flow coverage ratios and also require us to report indebtedness ratios to our lenders. The facility is secured by pledges of assets and interests in certain subsidiaries. We expect to remain in compliance with the covenants of the credit facility for at least the next 12 months.

Convertible Debentures

        In October 2006, we issued, in a public offering, Cdn$60 million aggregate principal amount of 6.25% convertible secured debentures, which we refer to as the 2006 Debentures, for gross proceeds of $52.8 million. The 2006 Debentures pay interest semi-annually on April 30 and October 31 of each year. The Debentures initially had a maturity date of October 31, 2011 and are convertible into approximately 80.6452 common shares per Cdn$1,000 principal amount of 2006 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per common share. The 2006 Debentures are secured by a subordinated pledge of our interest in certain subsidiaries and contain certain restrictive covenants. In connection with our conversion to a common share structure on November 27, 2009, the holders of the 2006 Debentures approved an amendment to increase the annual interest rate from 6.25% to 6.50% and separately, an extension of the maturity date from October 2011 to October 2014. During fiscal year 2010 and fiscal year 2011 through March 18, 2011, Cdn$4.2 million and Cdn$6.2 million of the 2006 Debentures, respectively, were converted to 0.3 million and 0.5 million common shares, respectively. As of March 18, 2011 the 2006 Debentures balance is Cdn$49.6 million ($50.8 million).

        In December 2009, we issued, in a public offering, Cdn$86.25 million aggregate principal amount of 6.25% convertible unsecured subordinated debentures, which we refer to as the 2009 Debentures, for gross proceeds of $82.1 million. The 2009 Debentures pay interest semi-annually on March 15 and September 15 of each year beginning September 15, 2010. The 2009 Debentures mature on March 15, 2017 and are convertible into approximately 76.9231 common shares per Cdn$1,000 principal amount of 2009 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$13.00 per common share. During fiscal year 2010 and fiscal year 2011 through March 18, 2011, Cdn$3.1 million and Cdn$6.4 million of the 2009 Debentures, respectively, were converted to 0.2 million and 0.5 million common shares, respectively. As of March 18, 2011 the 2009 Debentures balance is Cdn$76.7 million ($78.6 million).

        In October 2010, we issued, in a public offering, Cdn$80.5 million aggregate principal amount of 5.60% convertible unsecured subordinated debentures, which we refer to as the 2010 Debentures, for gross proceeds of $78.9 million. The 2010 Debentures pay interest semi-annually on June 30 and December 30 of each year beginning June 30, 2011. The 2010 Debentures mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial

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conversion rate of 55.2486 common shares per Cdn$1,000 principal amount of debentures, representing an initial conversion price of approximately Cdn$18.10 per common share. As of March 18, 2011 the 2010 debentures balance is Cdn$80.5 million ($82.5 million).

Project-level debt

        The following table summarizes the maturities of project-level debt. The amounts represent our share of the non-recourse project-level debt balances at December 31, 2010 and exclude any purchase accounting adjustments recorded to adjust the debt to its fair value at the time the project was acquired. Certain of the projects have more than one tranche of debt outstanding with different maturities, different interest rates and/or debt containing variable interest rates. Project-level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. As of December 31, 2010, the covenants at the Selkirk, Gregory and Delta-Person projects and at Epsilon Power Partners are temporarily preventing those projects from making cash distributions to us. We expect to resume receiving distributions from Epsilon Power Partners and Delta-Person in 2011, Selkirk in 2012 and Gregory in 2014. All project-level debt is non-recourse to us and substantially the entire principal is amortized over the life of the projects' PPAs. The non-recourse holding company debt relating to our investment in Chambers is held at Epsilon Power Partners, our wholly-owned subsidiary. For the year ended December 31, 2010, we have contributed approximately $3.1 million to Epsilon Power Partners for debt service payments on the holding company debt and an additional $0.48 million in January 2011 but do not anticipate any additional required contributions to Epsilon.

        The range of interest rates presented represents the rates in effect at December 31, 2010. The amounts listed below are in thousands of U.S. dollars, except as otherwise stated.

 
  Range of
Interest Rates
  Total
Remaining
Principal
Repayments
  2011   2012   2013   2014   2015   Thereafter  

Consolidated Projects:

                                               

Epsilon Power Partners

  7.40%   $ 36,482   $ 1,500   $ 1,500   $ 3,000   $ 5,000   $ 5,750   $ 19,732  

Path 15

  7.9% - 9.0%     153,868     7,987     8,667     9,402     8,065     8,749     110,998  

Auburndale

  5.10%     21,700     9,800     7,000     4,900              

Cadillac

  7.2% - 8.0%     42,531     2,300     3,791     2,400     2,000     2,500     29,540  
                                   

Total Consolidated Projects

        254,581     21,587     20,958     19,702     15,065     16,999     160,270  

Equity Method Projects:

                                               

Chambers

  0.4% - 7.2%     75,045     11,294     12,176     10,783     5,780     5,213     29,799  

Delta-Person

  2.0%     10,521     1,130     1,212     1,300     1,394     1,495     3,990  

Selkirk

  9.0%     16,793     10,948     5,845                  

Gregory

  1.8% - 7.5%     14,350     1,901     2,044     2,205     2,385     2,492     3,323  

Idaho Wind

  2.8% - 7.5%     71,008     34,198     1,657     1,753     1,939     2,020     29,441  
                                   

Total Equity Method Projects

        187,717     59,471     22,934     16,041     11,498     11,220     66,553  
                                   

Total Project-Level Debt

      $ 442,298   $ 81,058   $ 43,892   $ 35,743   $ 26,563   $ 28,219   $ 226,823  
                                   

        We also obtained project-level bank financing for Piedmont. The terms of the financing include an $82.0 million construction and term loan and a $51.0 million bridge loan for approximately 95.0% of the stimulus grant expected to be received from the U.S. Treasury 60 days after the start of commercial operations.

Restricted cash

        The projects generally have reserve requirements to support payments for major maintenance costs and project-level debt service. For projects that are consolidated, our share of these amounts is

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reflected as restricted cash on the consolidated balance sheet. At December 31, 2010, restricted cash at the consolidated projects totaled $15.7 million.


Capital Expenditures

        Capital expenditures for the projects are generally made at the project level using project cash flows and project reserves. Therefore, the distributions that we receive from the projects are made net of capital expenditures needed at the projects. The projects in which we have investments generally consist of large capital assets that have established commercial operations. Ongoing capital expenditures for assets of this nature are generally not significant because most major expenditures relate to planned repairs and maintenance and are expensed when incurred.

        In 2011, several of the projects have planned outages to complete maintenance work. The level of maintenance and capital expenditures is slightly higher than in 2010. During 2010, Selkirk completed a minor inspection of one of its combustion turbines, with costs and lost margin largely covered by reserves and gas resales proceeds, respectively. Selkirk's planned major overhaul of a steam turbine has been postponed to 2011 due to maintaining a high steam quality. In the second quarter of 2010, Chambers completed its scheduled outage to inspect and complete customary repairs on one boiler. Due to the facility's low dispatch, the planned outage of its other boiler originally scheduled for the fourth quarter of 2010 has been postponed to 2011. At Orlando, a minor gas turbine inspection was completed in May, the cost of which was largely covered under its long-term maintenance agreement with the gas turbine manufacturer. During the fourth quarter of 2010, Auburndale conducted an inspection of one of the facility's combustion turbines, which is covered by its long-term service agreement, in conjunction with other maintenance work.

        In 2010, we incurred approximately $48.0 million in capital expenditures for the construction of our Piedmont biomass project. In 2011, we expect to incur approximately $95.0 million in capital expenditures related to the Piedmont project, with total project costs through expected completion in late 2012 of approximately $207.0 million. The project will be funded with an $82.0 million construction loan which will convert to a term loan upon commercial operation, a $51.0 million bridge loan and approximately $75.0 million of equity contributed by Atlantic Power. The bridge loan will be repaid from the proceeds of a federal stimulus grant which is expected to be received two months after achieving commercial operation.


Contractual Obligations and Commercial Commitments

        The following table summarizes our contractual obligations as of December 31, 2010 (in thousands of U.S. dollars).

 
  Less than
1 Year
  1 - 3 Years   3 - 5 Years   Thereafter   Total  

Debt(a)

  $ 21,587   $ 111,829   $ 216,953   $ 124,829   $ 475,198  

Interest payments on debt

    31,824     84,008     57,177     48,254     221,263  

Total operating lease obligation

    922     1,949     78         2,949  

Total purchase obligations(b)

    102,730     50,830     6,649     17,572     177,781  

Total other long-term liabilities

    5,914     2,048         791     8,753  
                       

Total contractual obligations

  $ 162,977   $ 250,664   $ 280,857   $ 191,446   $ 885,944  
                       

(a)
Debt represents our consolidated share of project long-term debt and corporate-level debt. The amount presented excludes the net unamortized purchase price adjustment of $11.3 million related to the fair value of debt assumed in the Path 15 acquisition. Project debt is non-recourse to us and is generally amortized during the term of the respective revenue generating contracts of the

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(b)
Included in purchase obligations is $131.7 million related to construction costs for our Piedmont project.


Off-Balance Sheet Arrangements

        As of December 31, 2010, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of Regulation S-K.


Critical Accounting Policies and Estimates

        Accounting standards require information be included in financial statements about the risks and uncertainties inherent in significant estimates, and the application of generally accepted accounting principles involves the exercise of varying degrees of judgment. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

        In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining fair values of acquired assets, the useful lives and recoverability of property, plant and equipment and PPAs, the recoverability of equity investments, the recoverability of deferred tax assets, the valuation of shares associated with our Long-Term Incentive Plan and the fair value of derivatives.

        For a summary of our significant accounting policies, see Note 2 to our consolidated financial statements included in this Form 10-K. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others; these policies are discussed below.

        Long-lived assets, which include property, plant and equipment, transmission system rights and other intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability weights a range of possible outcomes. We also consider quoted market prices in active markets to the extent they are available. In the absence of such information, we may consider prices of similar assets, consult with brokers or employ other valuation techniques. We use our best estimates in making these evaluations. However, actual results could vary from the assumptions used in our estimates and the impact of such variations could be material.

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        Investments in and the operating results of 50%-or-less owned entities not required to be consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment, failure of cash flow coverage ratio tests included in project-level, non-recourse debt or, where applicable, estimated sales proceeds which are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary.

        When we determine that an impairment test is required, the future projected cash flows from the equity investment are the most significant factor in determining whether impairment exists and, if so, the amount of the impairment charges. We use our best estimates of market prices of power and fuel and our knowledge of the operations of the project and our related contracts when developing these cash flow estimates. In addition, when determining fair value using discounted cash flows, the discount rate used can have a material impact on the fair value determination. Discount rates are based on our risk of the cash flows in the estimate, including, when applicable, the credit risk of the counterparty that is contractually obligated to purchase electricity or steam from the project.

        We generally consider our investments in our equity method investees to be strategic long-term investments that comprise a significant portion of our core operating business. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, an appropriate write-down is recorded based on the excess of the carrying value over the best estimate of fair value of the investment. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in our estimates and the impact of such variations could be material.

        We utilize derivative contracts to mitigate our exposure to fluctuations in fuel commodity prices and foreign currency and to balance our exposure to variable interest rates. We believe that these derivatives are generally effective in realizing these objectives.

        In determining fair value for our derivative assets and liabilities, we generally use the market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk and/or the risks inherent in the inputs to the valuation techniques.

        A fair value hierarchy exists for inputs used in measuring fair value that maximizes the use of observable inputs (Level 1 or Level 2) and minimizes the use of unobservable inputs (Level 3) by requiring that the observable inputs be used when available. Our derivative instruments are classified as Level 2. The fair value measurements of these derivative assets and liabilities are based largely on quoted prices from independent brokers in active markets who regularly facilitate our transactions. An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis.

        Derivative assets are discounted for credit risk using credit spreads representative of the counter-party's probability of default. For derivative liabilities, fair value measurement reflects the nonperformance risk related to that liability, which is our own credit risk. We derive our

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nonperformance risk by applying credit spreads approximating our estimate of corporate credit rating against the respective derivative liability.

        Certain derivative instruments qualify for a scope exception to fair value accounting, as they are considered normal purchases or normal sales. The availability of this exception is based upon the assumption that we have the ability and it is probable to deliver or take delivery of the underlying physical commodity. Derivatives that are considered to be normal purchases and normal sales are exempt from derivative accounting treatment and are recorded as executory contracts.

        In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies. The valuation allowance is comprised primarily of provisions against available Canadian and U.S. net operating loss carryforwards.

        The officers and other employees of Atlantic Power are eligible to participate in the LTIP that was implemented in 2007. In the second quarter of 2010, the Board of Directors approved an amendment to the LTIP and the amended plan was approved by our shareholders on June 29, 2010. The amended LTIP will be effective for grants beginning with the 2010 performance year. Under the amended LTIP, the notional units granted to plan participants will have the same characteristics as notional units under the old LTIP. However, the number of notional units that vest will be based, in part, on the total shareholder return of Atlantic Power compared to a group of peer companies in Canada. In addition, vesting of the notional units for officers of Atlantic Power will occur on a three-year cliff basis as opposed to ratable vesting over three years for officers' grants made prior to the amendments.

        Unvested notional units are entitled to receive dividends equal to the dividends per common share during the vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the participant is not an employee at the vesting date or if we do not meet certain ongoing cash flow performance targets.

        Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards. The fair value of the awards granted prior to the 2010 amendment is determined by projecting the total number of notional units that will vest in future periods, including dividends received on notional units during the vesting period, and applying the current market price per share to the projected number of notional units that will vest. The fair value of awards granted for the 2010 performance period with market vesting conditions is based upon a Monte Carlo simulation model on their grant date. The aggregate number of shares which may be issued from treasury under the amended LTIP is limited to one million. Unvested notional units are recorded as either a liability or equity award based on management's intended method of redeeming the notional units when they vest.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and commodity prices, will affect our cash flows or the value of our holdings of financial instruments. The objective of market risk management is to minimize the impact that market risks have on our cash flows as described in the following paragraphs.

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        Our market risk-sensitive instruments and positions have been determined to be "other than trading." Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in fuel commodity prices, currency exchange rates or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in fuel commodity prices, currency exchange rates or interest rates and the timing of transactions.


Fuel Commodity Market Risk

        Our current and future cash flows are impacted by changes in electricity, natural gas and coal prices. The combination of long-term energy sales and fuel purchase agreements is generally designed to mitigate the impacts to cash flows of changes in commodity prices by generally passing through changes in fuel prices to the buyer of the energy.

        The Lake project's operating margin is exposed to changes in the market price of natural gas from the expiration of its natural gas supply contract on June 30, 2009 through to the expiration of its PPA on July 31, 2013 not passed through in their PPAs. The Auburndale project purchases natural gas under a fuel supply agreement which provides approximately 80% of the project's fuel requirements at fixed prices through June 30, 2012. The remaining 20% is purchased at market prices and therefore the project is exposed to changes in natural gas prices for that portion of its gas requirements through the termination of the fuel supply agreement and 100% of its natural gas requirements from the expiration of the fuel contract in mid-2012 until the termination of its PPA at the end of 2013.

        We have executed a strategy to mitigate the future exposure to changes in natural gas prices at Lake and Auburndale by periodically entering into financial swaps that effectively fix the price of natural gas required at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheet at fair value. Changes in the fair value of the natural gas swaps at Lake and Auburndale, through June 30, 2009 were recorded in other comprehensive income (loss) as they were designated as a hedge of the risk associated with changes in market prices of natural gas. As of July 1, 2009, these natural gas swap hedges were de-designated and the changes in their fair value are recorded in change in fair value of derivative instruments in the consolidated statements of operations.

        In 2011, projected cash distributions at Auburndale would change by approximately $0.8 million per $1.00/Mmbtu change in the price of natural gas based on the current level of un-hedged natural gas volumes at the project. In 2011, projected cash distributions at Lake would change by approximately $0.8 million per $1.00/Mmbtu change in the price of natural gas based on the current level of un-hedged natural gas volumes at the project.

        Coal prices used in the revenue component of the projected distributions from the Lake and Auburndale projects incorporate a forecast of the applicable Crystal River facility coal cost provided by the utility based on their internal projections. The projected annual cash distributions from Lake and Auburndale combined would change by approximately $2.5 million for every $0.25/Mmbtu change in the projected price of coal.

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        The following table summarizes the hedge position related to natural gas needed to meet PPA requirements at Lake and Auburndale as of December 31, 2010 and March 18, 2011:

 
  2011   2012   2013  

As of December 31, 2010

                   

Portion of gas volumes currently hedged:

                   
 

Lake:

                   
   

Contracted

             
   

Financially hedged

    78 %   90 %   65 %
               
   

Total

    78 %   90 %   65 %
               
 

Auburndale:

                   
   

Contracted

    80 %   40 %   0 %
   

Financially hedged

    13 %   32 %   79 %
               
   

Total

    93 %   72 %   79 %
               

Average price of financially hedged volumes (per Mmbtu)

                   
 

Lake

  $ 6.52   $ 6.90   $ 7.05  
 

Auburndale

  $ 6.68   $ 6.51   $ 6.92  

 

 
  2011   2012   2013  

As of March 18, 2011

                   

Portion of gas volumes currently hedged:

                   
 

Lake:

                   
   

Contracted

             
   

Financially hedged

    78 %   90 %   83 %
               
   

Total

    78 %   90 %   83 %
               
 

Auburndale:

                   
   

Contracted

    80 %   40 %   0 %
   

Financially hedged

    13 %   32 %   79 %
               
   

Total

    93 %   72 %   79 %
               

Average price of financially hedged volumes (per Mmbtu)

                   
 

Lake

  $ 6.52   $ 6.90   $ 6.63  
 

Auburndale

  $ 6.68   $ 6.51   $ 6.92  

        On October 18, 2010, we entered into natural gas swaps that are effective in 2014 and 2015. The natural gas swaps are related to our 50% share of expected fuel purchases at our Orlando project as its operating margin is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. These financial swaps effectively fix the price of 1.2 million Mmbtu of natural gas at the Orlando project at a weighted average price of $5.76/Mmbtu and represent approximately 25% of our share of the expected natural gas purchases at the project during 2014 and 2015.

        We expect cash distributions from Orlando to increase significantly following the expiration of the project's gas contract at the end of 2013 because both projected natural gas prices at that time and the prices in the natural gas swaps we have executed are lower than the price of natural gas being purchased under the project's gas contract.


Foreign Currency Exchange Risk

        We use forward foreign currency contracts to manage our exposure to changes in foreign exchange rates as we earn our income in U.S. dollars but pay dividends to shareholders in Canadian dollars.

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Since our inception, we have had an established hedging strategy for the purpose of mitigating the currency risk impact on the long-term sustainability of our dividends to shareholders. We have executed this strategy by entering into forward contracts to purchase Canadian dollars at fixed rates of exchange to hedge approximately 86% of our expected dividend and convertible debenture interest payments through 2013. Changes in the fair value of the forward contracts partially offset foreign exchange gains or losses on the U.S. dollar equivalent of our Canadian dollar obligations. The forward contracts consist of (1) monthly purchases through the end of 2013 of Cdn$6.0 million at an exchange rate of Cdn$1.134 per U.S. dollar and (2) purchases in both April and October 2011 of Cdn$1.9 million at an exchange rate of Cdn$1.1075 per U.S. dollar.

        It is our intention to periodically consider extending the length of these forward contracts. In addition, we will consider executing additional foreign currency forward contracts to hedge expected additional dividend and interest payments associated with the common shares and convertible debentures issued in our October 2010 public offering.

        The foreign exchange forward contracts are recorded at estimated fair value based on quoted market prices and the estimation of the counter-party's credit risk. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations.

        The following table contains the components of recorded foreign exchange (gain) loss for the years ended December 31, 2010, 2009 and 2008:

 
  Year ended December 31,  
 
  2010   2009   2008  

Unrealized foreign exchange (gain) loss:

                   
 

Subordinated notes and convertible debentures

  $ 9,153   $ 55,508   $ (85,212 )
 

Forward contracts and other

    (3,542 )   (31,138 )   46,009  
               

    5,611     24,370     (39,203 )

Realized foreign exchange gains on forward contract settlements

    (6,625 )   (3,864 )   (8,044 )
               

  $ (1,014 ) $ 20,506   $ (47,247 )
               

        The following table illustrates the impact on the fair value of our financial instruments of a 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar as of December 31, 2010:

Convertible debentures

  $ 22,062  

Foreign currency forward contracts

  $ (23,893 )


Interest Rate Risk

        Changes in interest rates do not have a significant impact on cash payments that are required on our debt instruments as approximately 86% of our debt, including our share of the project-level debt associated with equity investments in affiliates, either bears interest at fixed rates or is financially hedged through the use of interest rate swaps.

        We have executed an interest rate swap at our consolidated Auburndale project to economically fix a portion of its exposure to changes in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Auburndale debt. The interest rate swap was executed in November 2009 and expires on November 30, 2013.

Schedule I-81


Table of Contents

        We have an interest rate swap at our consolidated Cadillac project to economically fix a portion of its exposure to changes in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Cadillac debt. The interest rate swap expires on June 30, 2025.

        We executed two interest rate swaps at our consolidated Piedmont project to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements are not designated as hedges and changes in their fair market value are recorded in the statements of operations. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively.

        In accounting for cash flow hedges, gains and losses on the derivative contracts are reported in other comprehensive income, but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income. That is, for cash flow hedges, all effective components of the derivative contracts' gains and losses are recorded in other comprehensive income (loss), pending occurrence of the expected transaction. Other comprehensive income (loss) consists of those financial items that are included in "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets but not included in our net income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings until the expected transaction occurs.

        After considering the impact of interest rate swaps, a hypothetical change in the average interest rate of 100 basis points would change annual interest costs, including interest at equity investments, by approximately $0.9 million.

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

        Our consolidated financial statements are appended to the end of this Form 10-K, beginning on page F-1.

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

        None.

ITEM 9A.    CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

        Under the supervision of and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Form 10-K.

        This Annual Report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of the Company's registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

ITEM 9B.    OTHER INFORMATION

        None.

Schedule I-82


Table of Contents

PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

        The information concerning our directors and executive officers required by Item 10 will be included in the Proxy Statement and is incorporated herein by reference.

ITEM 11.    EXECUTIVE COMPENSATION

        The information concerning our directors and executive officers required by Item 11 will be included in the Proxy Statement and is incorporated herein by reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

        The information concerning security ownership and other matters required by Item 12 will be included in the Proxy Statement and is incorporated herein by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

        The information concerning certain relationships and related transactions required by Item 13 will be included in the Proxy Statement and is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

        The information concerning principal accountant fees and services required by Item 14 will be included in the Proxy Statement and is incorporated herein by reference.


PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

(a)(1)    Financial Statements

       
 

Consolidated Balance Sheets—December 31, 2010 and 2009

   
I-92
 
 

Consolidated Statements of Operations—Years ended December 31, 2010, 2009 and 2008

   
I-93
 
 

Consolidated Statements of Shareholders' Equity and Comprehensive Income/(Loss)—Years ended December 31, 2010, 2009 and 2008

   
I-94
 
 

Consolidated Statements of Cash Flows—Years ended December 31, 2010, 2009 and 2008

   
I-95
 
 

Notes to Consolidated Financial Statements

   
I-96
 
 

(a)(2)    Financial Statement Schedules

       
 

Schedule II—Valuation and Qualifying Accounts

   
I-142
 

Schedule I-83


Table of Contents

Exhibit
No.
  Description
  2.1   Plan of Arrangement of Atlantic Power Corporation, dated as of November 24, 2005 (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  3.1   Articles of Continuance of Atlantic Power Corporation, dated as of June 29, 2010 (incorporated by reference to our registration statement on Form 10-12B filed on July 9, 2010)
        
  4.1   Form of common share certificate (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  4.2   Trust Indenture, dated as of October 11, 2006 between Atlantic Power Corporation and Computershare Trust Company of Canada (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  4.3   First Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Secured Debentures, dated November 27, 2009, between Atlantic Power Corporation and Computershare Trust Company of Canada (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  4.4   Trust Indenture Providing for the Issue of Convertible Unsecured Subordinated Debentures, dated as of December 17, 2009, between Atlantic Power Corporation and Computershare Trust Company of Canada (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  4.5   Form of First Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Unsecured Subordinated Debentures, between Atlantic Power Corporation and Computershare Trust Company of Canada (incorporated by reference to our registration statement on Form S-1/A (File No. 33-138856) filed on September 27, 2010)
        
  10.1   Credit Agreement dated as of November 18, 2004 among Atlantic Power Holdings, Inc. as Borrower, Bank of Montreal as Administrative Agent, LC issuer and collateral agent and the Other Lenders party thereto, and Harris Nesbitt Corp. as arranger (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.2   Employment Agreement, dated as of December 31, 2009 between Atlantic Power Corporation and Barry Welch (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.3   Employment Agreement, dated as of December 31, 2009 between Atlantic Power Corporation and Patrick Welch (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.4   Employment Agreement, dated as of December 31, 2009 between Atlantic Power Corporation and Paul Rapisarda (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.5   Deferred Share Unit Plan, dated as of April 24, 2007 of Atlantic Power Corporation (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.6   Third Amended and Restated Long-Term Incentive Plan (incorporated by reference to our registration statement on Form 10-12B filed on July 9, 2010)
        

Schedule I-84


Table of Contents

Exhibit
No.
  Description
  16.1   Letter from KPMG LLP, Chartered Accountants, to the Securities and Exchange Commission, dated August 10, 2010 (incorporated by reference to our Current Report on Form 8-K filed on August 10, 2010)
        
  21.2   Subsidiaries of Atlantic Power Corporation (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  31.1 * Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
        
  31.2 * Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
        
  32.1 * Certification of the Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
        
  32.2 * Certification of the Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*
Filed herewith.

Schedule I-85


Table of Contents


SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 18, 2011   Atlantic Power Corporation

 

 

By:

 

/s/ PATRICK J. WELCH

        Name:   Patrick J. Welch
        Title:   Chief Financial Officer

 

Signature
 
Title
 
Date

 

 

 

 

 

 

 
/s/ BARRY E. WELCH

Barry E. Welch
  President, Chief Executive Officer and Director (principal executive officer)   March 18, 2011

/s/ PATRICK J. WELCH

Patrick J. Welch

 

Chief Financial Officer (principal financial and accounting officer)

 

March 18, 2011

/s/ IRVING R. GERSTEIN

Irving R. Gerstein

 

Chairman of the Board

 

March 18, 2011

/s/ KENNETH M. HARTWICK

Kenneth M. Hartwick

 

Director

 

March 18, 2011

/s/ R. FOSTER DUNCAN

R. Foster Duncan

 

Director

 

March 18, 2011

/s/ JOHN A. MCNEIL

John A. McNeil

 

Director

 

March 18, 2011

/s/ HOLLI NICHOLS

Holli Nichols

 

Director

 

March 18, 2011

Schedule I-86


Table of Contents

Exhibit
No.
  Description
  2.1   Plan of Arrangement of Atlantic Power Corporation, dated as of November 24, 2005 (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  3.1   Articles of Continuance of Atlantic Power Corporation, dated as of June 29, 2010 (incorporated by reference to our registration statement on Form 10-12B filed on July 9, 2010)
        
  4.1   Form of common share certificate (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  4.2   Trust Indenture, dated as of October 11, 2006 between Atlantic Power Corporation and Computershare Trust Company of Canada (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  4.3   First Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Secured Debentures, dated November 27, 2009, between Atlantic Power Corporation and Computershare Trust Company of Canada (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  4.4   Trust Indenture Providing for the Issue of Convertible Unsecured Subordinated Debentures, dated as of December 17, 2009, between Atlantic Power Corporation and Computershare Trust Company of Canada (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  4.5   Form of First Supplemental Indenture to the Trust Indenture Providing for the Issue of Convertible Unsecured Subordinated Debentures, between Atlantic Power Corporation and Computershare Trust Company of Canada (incorporated by reference to our registration statement on Form S-1/A (File No. 33-138856) filed on September 27, 2010)
        
  10.1   Credit Agreement dated as of November 18, 2004 among Atlantic Power Holdings, Inc. as Borrower, Bank of Montreal as Administrative Agent, LC issuer and collateral agent and the Other Lenders party thereto, and Harris Nesbitt Corp. as arranger (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.2   Employment Agreement, dated as of December 31, 2009 between Atlantic Power Corporation and Barry Welch (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.3   Employment Agreement, dated as of December 31, 2009 between Atlantic Power Corporation and Patrick Welch (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.4   Employment Agreement, dated as of December 31, 2009 between Atlantic Power Corporation and Paul Rapisarda (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.5   Deferred Share Unit Plan, dated as of April 24, 2007 of Atlantic Power Corporation (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  10.6   Third Amended and Restated Long-Term Incentive Plan (incorporated by reference to our registration statement on Form 10-12B filed on July 9, 2010)
        

Schedule I-87


Table of Contents

Exhibit
No.
  Description
  16.1   Letter from KPMG LLP, Chartered Accountants, to the Securities and Exchange Commission, dated August 10, 2010 (incorporated by reference to our Current Report on Form 8-K filed on August 10, 2010)
        
  21.2   Subsidiaries of Atlantic Power Corporation (incorporated by reference to our registration statement on Form 10-12B filed on April 13, 2010)
        
  31.1 * Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
        
  31.2 * Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
        
  32.1 * Certification of the Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
        
  32.2 * Certification of the Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*
Filed herewith.

Schedule I-88


Table of Contents

Atlantic Power Corporation
Index to Consolidated Financial Statements

 
  Page  

ANNUAL FINANCIAL STATEMENTS

       

Report of Independent Registered Public Accounting Firm

   
I-90
 

Consolidated Audited Financial Statements

       
 

Consolidated Balance Sheets

    I-92  
 

Consolidated Statements of Operations

    I-93  
 

Consolidated Statements of Shareholders' Equity

    I-94  
 

Consolidated Statements of Cash Flows

    I-95  
 

Notes to Consolidated Audited Financial Statements

    I-96  

Financial Statement Schedules

       
 

Schedule II—Valuation and Qualifying Accounts

    I-142  

Schedule I-89


Table of Contents

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Atlantic Power Corporation:

        We have audited the accompanying consolidated balance sheet of Atlantic Power Corporation and subsidiaries (the "Company") as of December 31, 2010, and the related consolidated statements of operations, shareholders' equity, and cash flows for the year then ended. In connection with our audit of the consolidated financial statements, we also have audited financial statement schedule "Schedule II Valuation and Qualifying Accounts." These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlantic Power Corporation and subsidiaries as of December 31, 2010, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

New York, New York
March 18, 2011

Schedule I-90


Table of Contents

Report of Independent Registered Public Accounting Firm

The Board of Directors
Atlantic Power Corporation

        We have audited the accompanying consolidated balance sheet of Atlantic Power Corporation as of December 31, 2009 and the related consolidated statements of operations, shareholders' equity and cash flows for each of the years in the two year period ended December 31, 2009. In connection with our audits of the consolidated financial statements, we also have audited financial statement "Schedule II. Valuation and Qualifying Accounts." These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statements presentation. We believe that our audits provide a reasonable basis for our opinion.

        As discussed in Note 2 to the consolidated financial statements on January 1, 2009, Atlantic Power Corporation adopted FASB's ASC 805 Business Combinations and on January 1, 2008, Atlantic Power Corporation changed its method of account for fair value measurements in accordance with FASB ASC 820 Fair Value Measurement.

        In our opinion the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlantic Power Corporation as of December 31, 2009 and the results of its operations and its cash flows for each of the years in the two year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Chartered Accountants, Licensed Public Accountants

Toronto, Canada

        April 12, 2010, except as to notes 4, 8 and 17, which are as of May 26, 2010 and as to Notes 2(a) and 16 which are as of June 16, 2010.

Schedule I-91


Table of Contents


ATLANTIC POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands of U.S. dollars)

 
  December 31,  
 
  2010   2009  

Assets

             

Current assets:

             
 

Cash and cash equivalents

  $ 45,497   $ 49,850  
 

Restricted cash

    15,744     14,859  
 

Accounts receivable

    19,362     17,480  
 

Note receivable—related party (Note 17)

    22,781      
 

Current portion of derivative instruments asset (Notes 11 and 12)

    8,865     5,619  
 

Prepayments, supplies, and other

    4,889     3,019  
 

Deferred income taxes (Note 13)

        17,887  
 

Refundable income taxes (Note 13)

    1,593     10,552  
           
 

Total current assets

    118,731     119,266  

Property, plant, and equipment, net (Note 5)

   
275,421
   
193,822
 

Transmission system rights (Note 6)

    188,134     195,984  

Equity investments in unconsolidated affiliates (Note 4)

    294,805     259,230  

Other intangible assets, net (Note 6)

    88,462     71,770  

Goodwill (Note 3)

    12,453     8,918  

Derivative instruments asset (Notes 11 and 12)

    17,884     14,289  

Other assets

    17,122     6,297  
           
 

Total assets

  $ 1,013,012   $ 869,576  
           

Liabilities

             

Current Liabilities:

             
 

Accounts payable and accrued liabilities

  $ 20,530   $ 21,661  
 

Current portion of long-term debt (Note 8)

    21,587     18,280  
 

Current portion of derivative instruments liability (Notes 11 and 12)

    10,009     6,512  
 

Interest payable on convertible debentures (Note 10)

    3,078     800  
 

Dividends payable

    6,154     5,242  
 

Other current liabilities

    5     752  
           
 

Total current liabilities

    61,363     53,247  

Long-term debt (Note 8)

   
244,299
   
224,081
 

Convertible debentures (Note 10)

    220,616     139,153  

Derivative instruments liability (Notes 11 and 12)

    21,543     5,513  

Deferred income taxes (Note 13)

    29,439     28,619  

Other non-current liabilities

    2,376     4,846  

Commitments and contingencies (Note 19)

             

Equity

             

Common shares, no par value, unlimited authorized shares; 67,118,154 and 60,404,093 issued and outstanding at December 31, 2010 and 2009, respectively

    626,108     541,917  
 

Accumulated other comprehensive income (loss) (Note 12)

    255     (859 )
 

Retained deficit

    (196,494 )   (126,941 )
           
 

Total Atlantic Power Corporation shareholders' equity

    429,869     414,117  
           

Noncontrolling interest (Note 3)

    3,507      
           

Total equity

    433,376     414,117  
           

Total liabilities and equity

  $ 1,013,012   $ 869,576  
           

See accompanying notes to consolidated financial statements.

Schedule I-92


Table of Contents


ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands of U.S. dollars, except per share amounts)

 
  Years ended December 31,  
 
  2010   2009   2008  

Project revenue:

                   
 

Energy sales

  $ 69,116   $ 58,953   $ 64,237  
 

Energy capacity revenue

    93,567     88,449     77,691  
 

Transmission services

    31,000     31,000     31,528  
 

Other

    1,573     1,115     356  
               

    195,256     179,517     173,812  

Project expenses:

                   
 

Fuel

    65,553     59,522     55,366  
 

Operations and maintenance

    26,506     24,038     17,711  
 

Project operator fees and expenses

    4,731     4,115     3,727  
 

Depreciation and amortization

    40,387     41,374     29,528  
               

    137,177     129,049     106,332  

Project other income (expense):

                   
 

Change in fair value of derivative instruments (Notes 11 and 12)

    (14,047 )   (6,813 )   (16,026 )
 

Equity in earnings of unconsolidated affiliates (Note 4)

    13,777     8,514     1,895  
 

Gain on sales of equity investments, net (Note 3)

    1,511     13,780      
 

Interest expense, net

    (17,660 )   (18,800 )   (17,709 )
 

Other income, net

    219     1,266     5,366  
               

    (16,200 )   (2,053 )   (26,474 )
               

Project income

    41,879     48,415     41,006  

Administrative and other expenses (income):

                   
 

Management fees and administration

    16,149     26,028     10,012  
 

Interest, net

    11,701     55,698     43,275  
 

Foreign exchange (gain) loss (Note 12)

    (1,014 )   20,506     (47,247 )
 

Other (income) expense, net

    (26 )   362     425  
               

    26,810     102,594     6,465  
               

Income (loss) from operations before income taxes

    15,069     (54,179 )   34,541  

Income tax expense (benefit) (Note 13)

    18,924     (15,693 )   (13,560 )
               

Net income (loss)

    (3,855 )   (38,486 )   48,101  

Net loss attributable to noncontrolling interest

    (103 )        
               

Net income (loss) attributable to Atlantic Power Corporation

  $ (3,752 ) $ (38,486 ) $ 48,101  
               

Net income (loss) per share attributable to Atlantic Power Corporation shareholders: (Note 15)

                   
 

Basic

  $ (0.06 ) $ (0.63 ) $ 0.78  
 

Diluted

  $ (0.06 ) $ (0.63 ) $ 0.73  

See accompanying notes to consolidated financial statements.

Schedule I-93


Table of Contents


ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(In thousands of U.S. dollars)

 
  Atlantic Power Corporation Shareholders    
   
 
 
  Common
Stock
(Shares)
  Common
Stock
(Amount)
  Retained
Deficit
  Accumulated
Other
Comprehensive
Income
  Noncontrolling
Interest
  Total
Shareholders'
Equity
 

December 31, 2007

    61,470   $ 216,636   $ (108,832 ) $   $   $ 107,804  

Common shares issued for LTIP

   
30
   
127
   
   
   
   
127
 

Common stock repurchases

    (559 )   (1,600 )               (1,600 )

Adoption of accounting standard for Fair Value Measurement

            25,179             25,179  

Dividends declared

            (24,849 )           (24,849 )

Comprehensive Income:

                                     
 

Net loss

            48,101             48,101  
 

Unrealized loss on hedging activities, net of tax of $2,091

                (3,136 )       (3,136 )
                                     
 

Net comprehensive income

                        44,965  
                           

December 31, 2008

    60,941     215,163     (60,401 )   (3,136 )       151,626  

Subordinated notes conversion

   
(114

)
 
327,691
   
   
   
   
327,691
 

Common shares issued for LTIP

    59     151                 151  

Common stock repurchases

    (482 )   (1,088 )               (1,088 )

Dividends declared

            (28,054 )           (28,054 )

Comprehensive Income:

                                     
 

Net loss

            (38,486 )           (38,486 )
 

Unrealized loss on hedging activities, net of tax of ($1,518)

                2,277         2,277  
                                     
 

Net comprehensive income

                        (36,209 )
                           

December 31, 2009

    60,404     541,917     (126,941 )   (859 )       414,117  

Convertible debenture conversion

   
579
   
7,147
   
   
   
   
7,147
 

Common shares issuance

    6,029     75,267                 75,267  

Common shares issued for LTIP

    106     1,325                 1,325  

LTIP amendment (Note 14)

        2,952                 2,952  

Piedmont equity costs

          (2,500 )               (2,500 )

Noncontrolling interest

                    3,507     3,507  

Dividends declared

            (65,801 )           (65,801 )

Comprehensive Income:

                                     
 

Net loss

            (3,752 )           (3,752 )
 

Unrealized gain on hedging activities, net of tax of $743

                1,114         1,114  
                                     
 

Net comprehensive income

                        (2,638 )
                           

December 31, 2010

    67,118   $ 626,108   $ (196,494 ) $ 255   $ 3,507   $ 433,376  
                           

See accompanying notes to consolidated financial statements.

Schedule I-94


Table of Contents


ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands of U.S. dollars)

 
  Years ended December 31,  
 
  2010   2009   2008  

Cash flows from operating activities:

                   

Net loss

  $ (3,855 ) $ (38,486 ) $ 48,101  

Adjustments to reconcile to net cash provided by operating activities:

                   
 

Depreciation and amortization

    40,387     41,374     29,528  
 

Common share conversions recorded in interest expense

        4,508      
 

Subordinated note redemption premium recorded in interest expense

        1,935      
 

Long-term incentive plan expense

    4,497          
 

(Gain) loss on sale of assets

    (1,511 )   (12,847 )   (5,163 )
 

Earnings from unconsolidated affiliates

    (16,913 )   (14,213 )   (1,895 )
 

Impairment of equity investments

    3,136     5,500      
 

Distributions from unconsolidated affiliates

    16,843     27,884     41,031  
 

Unrealized foreign exchange loss (gain)

    5,611     24,370     (39,203 )
 

Change in fair value of derivative instruments

    14,047     6,813     16,026  
 

Change in deferred income taxes

    17,964     (6,436 )   (14,009 )
 

Other

    (210 )   106     27  

Change in other operating balances

                   
 

Accounts receivable

    1,729     10,520     216  
 

Prepayments, refundable income taxes and other assets

    9,311     (3,454 )   12,229  
 

Accounts payable and accrued liabilities

    (6,551 )   2,959     (20 )
 

Other liabilities

    2,468     (84 )   (9,080 )
               

Net cash provided by operating activities

    86,953     50,449     77,788  

Cash flows (used in) provided by investing activities:

                   
 

Acquisitions and investments, net of cash acquired

    (78,180 )   (3,068 )   (141,688 )
 

Short-term loan to Idaho Wind

    (22,781 )        
 

Change in restricted cash

    945     575     6,335  
 

Biomass development costs

    (2,286 )        
 

Proceeds from sale of assets

    2,000     29,467     7,889  
 

Purchase of property, plant and equipment

    (46,695 )   (2,016 )   (1,102 )
 

Purchases of auction rate securities

            (75,518 )
 

Sales of auction rate securities

            75,518  
               

Net cash (used in) provided by investing activities

    (146,997 )   24,958     (128,566 )

Cash flows (used in) provided by financing activities:

                   
 

Proceeds from issuance of convertible debenture, net of offering costs

    74,575          
 

Proceeds from issuance of equity, net of offering costs

    72,767          
 

Deferred financing costs

    (7,941 )          
 

Repayment of project-level debt

    (18,882 )   (12,744 )   (22,275 )
 

Proceeds from revolving credit facility borrowings

    20,000         55,000  
 

Repayments of revolving credit facility borrowings

    (20,000 )   (55,000 )    
 

Dividends paid

    (65,028 )   (24,955 )   (24,612 )
 

Equity contribution from noncontrolling interest

    200          
 

Proceeds from issuance of project level debt

        78,330     35,000  
 

Redemption of IPSs under normal course issuer bid

        (3,369 )   (1,612 )
 

Redemption of subordinated notes

        (40,638 )   (3,064 )
 

Costs associated with common share conversion

        (4,508 )    
               

Net cash provided by (used in) financing activities

    55,691     (62,884 )   38,437  
               

Net (decrease) increase in cash and cash equivalents

    (4,353 )   12,523     (12,341 )

Cash and cash equivalents at beginning of period

    49,850     37,327     49,668  
               

Cash and cash equivalents at end of period

  $ 45,497   $ 49,850   $ 37,327  
               

Supplemental cash flow information

                   
 

Interest paid

  $ 26,687   $ 69,186   $ 72,129  
 

Income taxes paid (refunded), net

  $ (8,000 ) $ (216 ) $ 2,418  

See accompanying notes to consolidated financial statements.

Schedule I-95


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Business

Overview

        Atlantic Power Corporation ("Atlantic Power") is a corporation established under the laws of the Province of Ontario, Canada on June 18, 2004 and continued to the Province of British Columbia on July 8, 2005. We issued income participating securities ("IPSs") for cash pursuant to an initial public offering on the Toronto Stock Exchange, or the TSX, on November 18, 2004. Each IPS was comprised of one common share and Cdn$5.767 principal value of 11% subordinated notes due 2016. On November 27, 2009 our shareholders approved a conversion from the IPS structure to a traditional common share structure. Each IPS has been exchanged for one new common share and each old common share that did not form a part of an IPS was exchanged for approximately 0.44 of a new common share. Our shares trade on the TSX under the symbol "ATP" and began trading on the New York Stock Exchange, or the NYSE, under the symbol "AT" on July 23, 2010.

        We own interests in power projects for 13 operational power generation projects across ten states, one biomass project under construction in Georgia, a 500 kilovolt 84-mile electric transmission line located in California and a number of development projects. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,962 megawatts (or "MW"), in which our ownership interest is approximately 878 MW. Five of our projects are wholly-owned subsidiaries: Lake Cogen, Ltd., Pasco Cogen, Ltd., Auburndale Power Partners, L.P., Cadillac Renewable Energy, LLC and Atlantic Path 15, LLC. The consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles ("GAAP") with a reconciliation to Canadian GAAP in Note 22. The Canadian securities legislation allows issuers that are required to file reports with the Securities and Exchange Commission ("SEC") in the United States to file financial statements under United States GAAP to meet their continuous disclosure obligations in Canada. Prior to 2010, we prepared our consolidated financial statements in accordance with Canadian GAAP.

        Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia V6C 2G8 and our headquarters is located at 200 Clarendon Street, Floor 25, Boston, Massachusetts, USA 02116. The telephone number is (617) 977-2400. The address of our website is www.atlanticpower.com. Our recent U.S. and Canadian securities filings are available through our website.

2. Summary of significant accounting policies

(a)   Principles of consolidation and basis of presentation:

        The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America and include the consolidated accounts and operations of our subsidiaries in which we have a controlling financial interest. The usual condition for a controlling financial interest is ownership of the majority of the voting interest of an entity. However, a controlling financial interest may also exist in entities, such as a variable interest entity, through arrangements that do not involve controlling voting interests.

        We apply the standard that requires consolidation of variable interest entities ("VIEs"), for which we are the primary beneficiary. The guidance requires a variable interest holder to consolidate a VIE if that party has both the power to direct the activities that most significantly impact the entities' economic performance, as well as either the obligation to absorb losses or the right to receive benefits

Schedule I-96


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)


that could potentially be significant to the VIE. We have determined that our investments are not VIEs by evaluating their design and capital structure. Accordingly, we use the equity method of accounting for all of our investments in which we do not have an economic controlling interest. We eliminate all intercompany accounts and transactions in consolidation.

(b)   Use of estimates:

        The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and valuation assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment and power purchase agreements ("PPAs"), the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the valuation of shares associated with our Long-Term Incentive Plan and the fair value of financial instruments and derivatives. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. These estimates and valuation assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

(c)   Regulatory accounting:

        Path 15 accounts for certain income and expense items in accordance with a standard where certain costs are deferred, which would otherwise be charged to expense, as regulatory assets based on Path 15's ability to recover these costs in future rates.

(d)   Revenue:

        We recognize energy sales revenue on a gross basis when electricity and steam are delivered under the terms of the related contracts. Revenue associated with capacity payments under the PPAs are recognized as the lesser of (1) the amount billable under the PPA or (2) an amount determined by the kilowatt hours made available during the period multiplied by the estimated average revenue per kilowatt hour over the term of the PPA.

        Transmission services revenue is recognized as transmission services are provided. The annual revenue requirement for transmission services is regulated by the Federal Energy Regulatory Commission ("FERC") and is established through a rate-making process that occurs every three years. When actual cash receipts from transmission services revenue are different than the regulated revenue requirement because of timing differences, the over or under collections are deferred until the timing differences reverse in future periods.

(e)   Cash and cash equivalents:

        Cash and cash equivalents include cash deposited at banks and highly liquid investments with original maturities of 90 days or less when purchased.

Schedule I-97


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)

(f)    Restricted cash:

        Restricted cash represents cash and cash equivalents that are maintained by the Projects to support payments for major maintenance costs and meet project-level contractual debt obligations.

(g)   Use of fair value:

        We utilize a fair value hierarchy that gives the highest priority to quoted prices in active markets and is applicable to fair value measurements of derivative contracts and other instruments that are subject to mark-to-market accounting. Refer to Note 11 for more information.

(h)   Derivative financial instruments:

        We use derivative financial instruments in the form of interest rate swaps and foreign exchange forward contracts to manage our current and anticipated exposure to fluctuations in interest rates and foreign currency exchange rates. We have also entered into natural gas supply contracts and natural gas forwards or swaps to minimize the effects of the price volatility of natural gas, which is a major production cost. We do not enter into derivative financial instruments for trading or speculative purposes; however, not all derivatives qualify for hedge accounting.

        Derivative financial instruments not designated as a hedge are measured at fair value with changes in fair value recorded in the consolidated statements of operations.

        The following table summarizes derivative financial instruments that are not designated as hedges for accounting purposes and the accounting treatment in the consolidated statements of operations of the changes in fair value and cash settlements of such derivative financial instrument:

Derivative financial instrument
  Classification of changes in fair value   Classification of cash settlements

Foreign currency forward contracts

  Foreign exchange loss (gain)   Foreign exchange loss (gain)

Lake natural gas swaps

  Change in fair value of derivative instruments   Fuel expense

Auburndale natural gas swaps

  Change in fair value of derivative instruments   Fuel expense

Orlando natural gas swaps

  Change in fair value of derivative instruments   Fuel expense

Interest rate swaps

  Change in fair value of derivative instruments   Interest expense

        Certain derivative instruments qualify for a scope exception to fair value accounting because they are considered normal purchases or normal sales. This exception applies when we have the ability to and it is probable that we will deliver or take delivery of the underlying physical commodity. Derivatives that are considered to be normal purchases and normal sales are exempt from derivative accounting treatment and are recorded as executory contracts.

        We have designated two of our interest rate swaps as a hedge of cash flows for accounting purposes. Tests are performed to evaluate hedge effectiveness and ineffectiveness at inception and on an ongoing basis, both retroactively and prospectively. Unrealized gains or losses on the interest rate swap designated as a hedge are deferred and recorded as a component of accumulated other comprehensive income (loss) until the hedged transactions occur and are recognized in earnings. The ineffective portion of the cash flow hedge, if any, is immediately recognized in earnings.

Schedule I-98


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)

(i)    Property, plant and equipment:

        Property, plant and equipment are stated at cost, net of accumulated depreciation. Depreciation is provided on a straight-line basis over the estimated useful life of the related asset. As major maintenance occurs and parts are replaced on the plant's combustion and steam turbines, maintenance costs are either expensed or transferred to property, plant and equipment if the maintenance extends the useful lives of the major parts. These costs are depreciated over the parts' estimated useful lives, which is generally three to six years, depending on the nature of maintenance activity performed.

(j)    Transmission system rights:

        Transmission system rights are an intangible asset that represents the long-term right to approximately 72% of the capacity of the Path 15 transmission line in California. Transmission system rights are amortized on a straight-line basis over 30 years, the regulatory life of Path 15.

(k)   Asset retirement obligations:

        The fair value for an asset retirement obligation is recorded in the period in which it is incurred. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. When the liability is initially recorded, we capitalize the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss.

(l)    Impairment of long-lived assets, non-amortizing intangible assets and equity method investments:

        Long-lived assets, such as property, plant and equipment, transmission system rights and other intangible assets subject to depreciation and amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds its fair value.

        Investments in and the operating results of 50%-or-less owned entities not required to be consolidated are included in the consolidated financial statements on the basis of the equity method of accounting. We review our investments in such unconsolidated entities for impairment whenever events or changes in business circumstances indicate that the carrying amount of the investments may not be fully recoverable. Evidence of a loss in value that is other than temporary might include the absence of an ability to recover the carrying amount of the investment, the inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment, failure of cash flow coverage ratio tests included in project-level non-recourse debt or, where applicable, estimated sales proceeds which are insufficient to recover the carrying amount of the investment. Our assessment as to whether any decline in value is other than temporary is based on our ability and intent to hold the investment and whether evidence indicating the carrying value of the investment is recoverable within a

Schedule I-99


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)


reasonable period of time outweighs evidence to the contrary. We generally consider our investments in our equity method investees to be strategic long-term investments. Therefore, we complete our assessments with a long-term view. If the fair value of the investment is determined to be less than the carrying value and the decline in value is considered to be other than temporary, the asset is written down to its fair value.

(m)  Distributions from equity method investments:

        We make investments in entities that own power producing assets with the objective of generating accretive cash flow that is available to be distributed to our shareholders. The cash flows that are distributed to us from these unconsolidated affiliates are directly related to the operations of the affiliates' power producing assets and are classified as cash flows from operating activities in the consolidated statements of cash flows.

        We record the return of our investments in equity investees as cash flows from investing activities. Cash flows from equity investees are considered a return of capital when distributions are generated from proceeds of either the sale of our investment in its entirety or a sale by the investee of all or a portion of its capital assets.

(n)   Goodwill:

        Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the assets acquired, less liabilities assumed, based on their fair values. Goodwill is allocated, as of the date of the business combination, to our reporting units that are expected to benefit from the synergies of the business combination.

        Goodwill is not amortized and is tested for impairment, annually in the fourth quarter, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the reporting unit is compared with its fair value. When the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not to be impaired and the second step of the impairment test is unnecessary.

        The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case, the implied fair value of the reporting unit's goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of goodwill is determined in a business combination described in the preceding paragraph, using the fair value of the reporting unit as if it were the purchase price. When the carrying amount of reporting unit goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess and is recorded in the consolidated statements of operations.

(o)   Other intangible assets:

        Other intangible assets include PPAs and fuel supply agreements at our projects.

        PPAs are valued at the time of acquisition based on the contract prices under the PPAs compared to projected market prices. Fuel supply agreements are valued at the time of acquisition based on the contract prices under the fuel supply agreement compared to projected market prices. The balances are

Schedule I-100


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)


presented net of accumulated amortization in the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the agreement.

(p)   Income taxes:

        Income tax expense includes the current tax obligation or benefit and change in deferred income tax asset or liability for the period. We use the asset and liability method of accounting for deferred income taxes and record deferred income taxes for all significant temporary differences. Income tax benefits associated with uncertain tax positions are recognized when we determine that it is more-likely-than-not that the tax position will be ultimately sustained. Refer to Note 13 for more information.

(q)   Foreign currency translation:

        Our functional currency and reporting currency is the United States dollar. The functional currency of our subsidiaries and other investments is the United States dollar. Monetary assets and liabilities denominated in Canadian dollars are translated into United States dollars using the rate of exchange in effect at the end of the period. All transactions denominated in Canadian dollars are translated into United States dollars at average exchange rates.

(r)   Long-term incentive plan:

        The officers and other employees of Atlantic Power are eligible to participate in the Long-Term Incentive Plan ("LTIP") that was implemented in 2007. In the second quarter of 2010, the Board of Directors approved an amendment to the LTIP and the amended plan was approved by our shareholders on June 29, 2010. The amended LTIP will be effective for grants beginning with the 2010 performance year. Under the amended LTIP, the notional units granted to plan participants will have the same characteristics as notional units under the old LTIP. However, the number of notional units that vest will be based, in part, on the total shareholder return of Atlantic Power compared to a group of peer companies in Canada. In addition, vesting of the notional units for officers of Atlantic Power will occur on a three-year cliff basis as opposed to ratable vesting over three years for grants made prior to the amendment.

        Unvested notional units are entitled to receive dividends equal to the dividends per common share during the vesting period in the form of additional notional units. Unvested units are subject to forfeiture if the participant is not an employee at the vesting date or if we do not meet certain ongoing cash flow performance targets.

        Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards. Fair value of the awards granted prior to the 2010 amendment is determined by projecting the total number of notional units that will vest in future periods, including dividends received on notional units during the vesting period, and applying the current market price per share to the projected number of notional units that will vest. The fair value of awards granted for the 2010 performance period with market vesting conditions is based upon a Monte Carlo simulation model on their grant date. The aggregate number of shares which may be issued from treasury under

Schedule I-101


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)


the LTIP is limited to one million. Unvested notional units are recorded as either a liability or equity award based on management's intended method of redeeming the notional units when they vest.

(s)   Deferred financing costs:

        Deferred financing costs represent costs to obtain long-term financing and are amortized using the effective interest method over the term of the related debt which range from five to 28 years. The net carrying amount of deferred financing costs recorded in other assets on the consolidated balance sheets was $16.7 million and $5.5 million at December 31, 2010 and 2009, respectively. Amortization expense for the years ended December 31, 2010, 2009 and 2008 was $1.2 million, $14.6 million, and $1.1 million, respectively.

(t)    Concentration of credit risk:

        The financial instruments that potentially expose us to credit risk consist primarily of cash and cash equivalents, restricted cash, derivative instruments and accounts receivable. Cash and restricted cash are held by major financial institutions that are also counterparties to our derivative instruments. We have long-term agreements to sell electricity, gas and steam to public utilities and corporations. We have exposure to trends within the energy industry, including declines in the creditworthiness of our customers. We do not normally require collateral or other security to support energy-related accounts receivable. We do not believe there is significant credit risk associated with accounts receivable due to payment history. See Note 16, Segment and related information, for a further discussion of customer concentrations.

(u)   Segments:

        We have six reportable segments: Auburndale, Lake, Pasco, Chambers, Path 15 and Other Project Assets. Each of our projects is an operating segment. Based on similar economic and other characteristics, we aggregate several of the projects into the Other Project Assets reportable segment.

(v)   Recently issued accounting standards:

        In December 2010, the FASB issued changes to the disclosure of pro forma information for business combinations. These changes clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Also, the existing supplemental pro forma disclosures were expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We adopted these changes beginning January 1, 2011. Upon adoption, we determined these changes did not impact the consolidated financial statements.

        In December 2010, the FASB issued changes to the testing of goodwill for impairment. These changes require an entity to perform all steps in the test for a reporting unit whose carrying value is zero or negative if it is more likely than not (more than 50%) that a goodwill impairment exists based on qualitative factors, resulting in the elimination of an entity's ability to assert that such a reporting unit's goodwill is not impaired and additional testing is not necessary despite the existence of

Schedule I-102


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)


qualitative factors that indicate otherwise. We adopted these changes beginning January 1, 2011. Based on the most recent impairment review of our goodwill (2010 fourth quarter), we determined these changes did not impact the consolidated financial statements.

        On January 1, 2010, we adopted changes issued by the Financial Accounting Standards Board (FASB) to accounting for variable interest entities. These changes require an enterprise to perform an analysis to determine whether the enterprise's variable interest or interests give it a controlling financial interest in a variable interest entity; to require ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity; to eliminate the solely quantitative approach previously required for determining the primary beneficiary of a variable interest entity; to add an additional reconsideration event for determining whether an entity is a variable interest entity when any changes in facts and circumstances occur such that holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impact the entity's economic performance; and to require enhanced disclosures that will provide users of financial statements with more transparent information about an enterprise's involvement in a variable interest entity. The adoption of these changes had no impact on the consolidated financial statements.

        On January 1, 2010, we adopted changes issued by the FASB to accounting for transfers of financial assets. These changes remove the concept of a qualifying special-purpose entity and remove the exception from the application of variable interest accounting to variable interest entities that are qualifying special-purpose entities; limit the circumstances in which a transferor derecognizes a portion or component of a financial asset; define a participating interest; require a transferor to recognize and initially measure at fair value all assets obtained and liabilities incurred as a result of a transfer accounted for as a sale; and require enhanced disclosure. The adoption of these changes had no impact on the consolidated financial statements.

        Effective January 1, 2010, we adopted changes issued by the FASB on January 6, 2010 for a scope clarification to the FASB's previously-issued guidance on accounting for noncontrolling interests in consolidated financial statements. These changes clarify the accounting and reporting guidance for noncontrolling interests and changes in ownership interests of a consolidated subsidiary. An entity is required to deconsolidate a subsidiary when the entity ceases to have a controlling financial interest in the subsidiary. Upon deconsolidation of a subsidiary, an entity recognizes a gain or loss on the transaction and measures any retained investment in the subsidiary at fair value. The gain or loss includes any gain or loss associated with the difference between the fair value of the retained investment in the subsidiary and its carrying amount at the date the subsidiary is deconsolidated. In contrast, an entity is required to account for a decrease in its ownership interest of a subsidiary that does not result in a change of control of the subsidiary as an equity transaction. The adoption of these changes had no impact on the consolidated financial statements.

        Effective January 1, 2010, we adopted changes issued by the FASB on January 21, 2010 to disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The changes also clarify existing disclosure requirements related to how assets and liabilities should be grouped by class and valuation techniques used for recurring and nonrecurring fair value measurements. The adoption of these changes had no impact on the consolidated financial statements.

Schedule I-103


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)

        Effective January 1, 2010, we adopted changes issued by the FASB on February 24, 2010 to accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued, otherwise known as "subsequent events." Specifically, these changes clarify that an entity that is required to file or furnish its financial statements with the Securities and Exchange Commission is not required to disclose the date through which subsequent events have been evaluated. The adoption of these changes had no impact on the consolidated financial statements.

        On July 1, 2010, we adopted changes to existing accounting requirements for embedded credit derivatives. Specifically, the changes clarify the scope exception regarding when embedded credit derivative features are not considered embedded derivatives subject to potential bifurcation and separate accounting. The adoption of these changes had no impact on the consolidated financial statements.

        In October 2009, the FASB issued changes to revenue recognition for multiple-deliverable arrangements. These changes require separation of consideration received in such arrangements by establishing a selling price hierarchy (not the same as fair value) for determining the selling price of a deliverable, which will be based on available information in the following order: vendor-specific objective evidence, third-party evidence, or estimated selling price; eliminate the residual method of allocation and require that the consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method, which allocates any discount in the arrangement to each deliverable on the basis of each deliverable's selling price; require that a vendor determine its best estimate of selling price in a manner that is consistent with that used to determine the price to sell the deliverable on a standalone basis; and expand the disclosures related to multiple-deliverable revenue arrangements. These changes become effective on January 1, 2011. We have determined that the adoption of these changes will not have an impact on the consolidated financial statements, as our projects do not currently have any such arrangements with their customers.

        In January 2010, the FASB issued changes to disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose, in the reconciliation of fair value measurements using significant unobservable inputs (Level 3), separate information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one net number) of these Level 3 financial instruments. These changes become effective beginning January 1, 2011. Other than the additional disclosure requirements, we have determined these changes will not have an impact on the consolidated financial statements.

        In April 2010, the FASB issued changes to the classification of certain employee share-based payment awards. These changes clarify that there is not an indication of a condition that is other than market, performance, or service if an employee share-based payment award's exercise price is denominated in the currency of a market in which a substantial portion of the entity's equity securities trade and differs from the functional currency of the employer entity or payroll currency of the employee. An employee share-based payment award is required to be classified as a liability if the award does not contain a market, performance, or service condition. These changes become effective on January 1, 2011. We have determined these changes will not have an impact on the consolidated financial statements.

Schedule I-104


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Acquisitions and divestments

(a)   Cadillac

        On December 21, 2010, we acquired 100% of Cadillac Renewable Energy, LLC, which owns and operates a 39.6 MW wood fired facility in Cadillac, Michigan. The purchase price was funded by $37.0 million using a portion of the cash raised in the public equity and convertible debenture offerings in October 2010 and the assumption of $43.1 million of project-level debt. The cash payment for the acquisition was allocated to the net assets acquired based on our preliminary estimates of fair value.

        Total cash paid for the acquisition, less cash acquired in December 2010 was $35.1 million.

        The allocation of the purchase price to the net assets acquired is as follows:

Recognized amounts of identifiable assets acquired and liabilities assumed:

       
 

Working capital

  $ 5,643  
 

Property, plant and equipment

    42,101  
 

Power purchase agreements

    36,420  
 

Interest rate swap derivative

    (4,038 )
 

Project-level debt

    (43,131 )
       
 

Total purchase price

    36,995  
   

Less cash acquired

    (1,870 )
       
 

Cash paid, net of cash acquired

  $ 35,125  
       

(b)   Topsham

        During the three months ended December 31, 2010, we reviewed the recoverability of our 50.0% equity investment in the Topsham project. The review was undertaken as a result of the PPA expiring on December 31, 2011 and our view about the long-term economic viability of the plant upon this expiration.

        Based on this review we determined that the carrying value of the Topsham project was impaired and recorded a pre-tax long-lived asset impairment of $2.0 million during 2010. The Topsham project is accounted for under the equity method of accounting and the impairment charge is included in equity in earnings of unconsolidated affiliates in the consolidated statements of operations.

        On February 28, 2011, we entered into a purchase and sale agreement with a third party for the purchase of our lessor interest in the project. Closing of the transaction is expected to occur in the second quarter of 2011.

(c)   Rumford

        During the three months ended September 30, 2009, we reviewed the recoverability of our 23.5% equity investment in the Rumford project. The review was undertaken as a result of not receiving distributions from the Project through the first nine months of 2009 and our view about the long-term economic viability of the plant upon expiration of the project's PPA on December 31, 2009.

        Based on this review, we determined that the carrying value of the Rumford project was impaired and recorded a pre-tax long-lived asset impairment of $5.5 million during 2009. The Rumford project is

Schedule I-105


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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Acquisitions and divestments (Continued)


accounted for under the equity method of accounting and the impairment charge is included in equity in earnings of unconsolidated affiliates in the consolidated statements of operations.

        In the fourth quarter of 2009, Atlantic Power and the other limited partners in the Rumford project settled a dispute with the general partner related to the general partner's failure to pay distributions to the limited partners in 2009. Under the terms of the settlement, we received $2.9 million in distributions from Rumford in the fourth quarter of 2009. In addition, the general partner had agreed to purchase the interests of all the limited partners in June 2010. In November 2010 we received our share of the proceeds of $2.0 million and recognized a gain on sale of investment of $1.5 million.

(d)   Piedmont

        On October 21, 2010 we completed the closing of non-recourse, project-level bank financing for our Piedmont Green Power project ("Piedmont"). The terms of the financing include an $82.0 million construction and term loan and a $51.0 million bridge loan for approximately 95% of the stimulus grant expected to be received from the U.S. Treasury 60 days after the start of commercial operations. In addition, we will make an equity contribution of approximately $75.0 million for substantially all of the equity interest in the project. As of December 31, 2010 we have contributed $58.7 million and construction has commenced.

        Piedmont is a 53.5 MW biomass plant located in Barnesville, Georgia, approximately 70 miles south of Atlanta. The Project was developed and will be managed by Rollcast Energy, Inc., a biomass developer in which we own a 60% interest.

(e)   Idaho Wind

        On July 2, 2010, we acquired a 27.6% equity interest in Idaho Wind Partners 1, LLC ("Idaho Wind") for $38.9 million and approximately $3.1 million in transaction costs. Idaho Wind recently commenced construction of a 183 MW wind power project located near Twin Falls, Idaho, which is expected to be completed in early 2011. Idaho Wind has 20-year PPAs with Idaho Power Company. Our investment in Idaho Wind was funded with cash on hand and a $20.0 million borrowing under our senior credit facility, which was repaid in October 2010 with a portion of the proceeds from our public offering (see Note 10 and Note 18). Idaho Wind is accounted for under the equity method of accounting.

        During 2010, we made a short-term $22.8 million loan to Idaho Wind to provide temporary funding for construction of the project until a portion of the project-level construction financing is completed. Member loans will be paid down with a combination of excess proceeds from the federal stimulus cash grant after repaying the cash grant facility, funds from a third closing for additional debt, and project cash flow. The federal stimulus grant is expected in the second quarter of 2011 and a third closing is expected by the end of the year. The outstanding loans bear interest at a prime rate plus 10% (13.25% as December 31, 2010). As of March 18, 2011, $5.1 million of the loan has been repaid.

(f)    Rollcast

        On March 31, 2009, we acquired a 40% equity interest in Rollcast Energy, Inc., a North Carolina Corporation for $3.0 million in cash. On March 1, 2010, we paid $1.2 million in cash for an additional

Schedule I-106


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Acquisitions and divestments (Continued)


15% of the shares of Rollcast, increasing our interest from 40% to 55% and providing us control of Rollcast. We consolidated Rollcast as of that date. We previously accounted for our 40% interest in Rollcast as an equity method investment. On April 28, 2010, we paid an additional $0.8 million to increase our ownership interest in Rollcast to 60%.

        Rollcast is a developer of biomass power plants in the southeastern U.S. with several projects in various stages of development. The investment in Rollcast gives us the option but not the obligation to invest equity in Rollcast's biomass power plants.

        The following table summarizes the consideration transferred to acquire Rollcast and the preliminary estimated amounts of identifiable assets acquired and liabilities assumed at the March 1, 2010 acquisition date, as well as the fair value of the noncontrolling interest in Rollcast at the acquisition date:

Fair value of consideration transferred:

       
 

Cash

  $ 1,200  

Other items to be allocated to identifiable assets acquired and liabilities assumed:

       
 

Fair value of our investment in Rollcast at the acquisition date

    2,758  
 

Fair value of noncontrolling interest in Rollcast

    3,410  
 

Gain recognized on the step acquisition

    211  
       
 

Total

  $ 7,579  
       

Recognized amounts of identifiable assets acquired and liabilities assumed:

       
 

Cash

  $ 1,524  
 

Property, plant and equipment

    130  
 

Prepaid expenses and other assets

    133  
 

Capitalized development costs

    2,705  
 

Trade and other payables

    (448 )
       
 

Total identifiable net assets

    4,044  
 

Goodwill

    3,535  
       

  $ 7,579  
       

        As a result of obtaining control over Rollcast, our previously held 40% interest was remeasured to fair value, resulting in a gain of $0.2 million. This has been recognized in other income (expense) in the consolidated statements of operations.

        The fair value of the noncontrolling interest of $3.4 million in Rollcast was estimated by applying an income approach using the discounted cash flow method. This fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 fair value measurement. The fair value estimate utilized an assumed discount rate of 9.4% which is composed of a risk-free rate and an equity risk premium determined by the capital asset pricing of companies deemed to be similar to Rollcast. The estimate assumed that no fair value adjustments are required because of the lack of control or lack of marketability that market participants would consider when estimating the fair value of the noncontrolling interest in Rollcast.

Schedule I-107


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Acquisitions and divestments (Continued)

        The goodwill is attributable to the value of future biomass power plant development opportunities. It is not expected to be deductible for tax purposes. All of the $3.5 million of goodwill was assigned to the Other Project Assets segment.

(g)   Stockton

        On November 30, 2009, we sold our 50% interest in the assets of Stockton Cogen Company LP for a nominal cash payment. Stockton is a 55 MW coal/biomass cogeneration facility located in Stockton, California. During the year ended December 31, 2009, we recorded a loss on the sale of $2.0 million. The loss on sale was recorded in gain (loss) on sales of equity investments in the consolidated statements of operations.

(h)   Mid-Georgia

        On November 24, 2009, we sold our 50% interest in the assets of Mid-Georgia Cogen LP for $29.1 million. Mid-Georgia is a 308 MW dual-fueled, combined-cycle cogeneration plant located in Kathleen, Georgia. We recorded a gain on sale of asset of $15.8 million. The gain on sale was recorded in gain (loss) on sales of equity investments in the consolidated statements of operations.

(i)    Onondaga Renewables

        In the first quarter of 2009, we transferred our remaining net assets of Onondaga Cogeneration Limited Partnership at net book value, into a 50% owned joint venture, Onondaga Renewables, LLC, which is redeveloping the project into a 35-40 MW biomass power plant. Our investment in Onondaga Renewables is accounted for under the equity method of accounting.

(j)    Auburndale

        On November 21, 2008, we acquired 100% of Auburndale Power Partners, L.P., which owns and operates a 155 MW natural gas-fired combined cycle cogeneration facility located in Polk County, Florida. The purchase price was funded by cash on hand, a borrowing under our credit facility and $35 million of acquisition debt. The cash payment for the acquisition, including acquisition costs, was allocated to the net assets acquired based on our estimate of the fair value.

        Total cash paid for the acquisition, less cash acquired, during 2008 was $141.7 million. In 2009, we received a working capital adjustment from the sellers in the amount of $1.8 million, resulting in a final purchase price of $139.9 million.

Schedule I-108


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Acquisitions and divestments (Continued)

        The allocation of the purchase price to the net assets acquired is as follows:

Working capital

  $ 11,589  

Property, plant and equipment

    56,301  

Power purchase agreements

    45,980  

Fuel supply agreements

    33,846  

Other long-term assets

    663  
       

Total purchase price

    148,379  

Less cash acquired

    (8,471 )
       

Cash paid, net of cash acquired

  $ 139,908  
       

4. Equity method investments

        During the three months ended December 31, 2010, we reviewed the recoverability of our 50.0% equity investment in the Badger Creek project. The review was undertaken as a result of the project's recent discussions with utilities in California, the current status of the regulatory proceedings related to contract pricing for qualified facilities in California and recent comparable market transactions in the region.

        Based on this review we determined that the carrying value of the Badger Creek project was impaired and recorded a pre-tax long-lived asset impairment of $1.2 million during 2010. The Badger Creek project is accounted for under the equity method of accounting and the impairment charge is included in equity in earnings of unconsolidated affiliates in the consolidated statements of operations.

        The following tables summarize our equity method investments:

 
   
  Carrying value as of
December 31,
 
 
  Percentage of
Ownership as of
December 31,
2010
 
Entity name
  2010   2009  

Rollcast Energy, Inc.*

    60.0 % $   $ 2,801  

Badger Creek Limited

    50.0 %   7,839     9,949  

Orlando Cogen, LP

    50.0 %   31,543     36,387  

Topsham Hydro Assets

    50.0 %   8,500     10,825  

Onondaga Renewables, LLC

    50.0 %   1,761     1,757  

Koma Kulshan Associates

    49.8 %   6,491     7,003  

Chambers Cogen, LP

    40.0 %   139,855     129,501  

Delta-Person, LP

    40.0 %        

Idaho Wind Partners 1, LLC

    27.6 %   41,376      

Selkirk Cogen Partners, LP

    18.5 %   53,575     57,030  

Gregory Power Partners, LP

    17.1 %   3,662     2,931  

Other

        203     1,046  
                 

Total

        $ 294,805   $ 259,230  
                 

*
Rollcast was consolidated in the first quarter of 2010.

Schedule I-109


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Equity method investments (Continued)

        Equity in earnings (loss) of unconsolidated affiliates was as follows:

 
  Year Ended December 31,  
Entity name
  2010   2009   2008  

Rollcast Energy, Inc.

  $ (66 ) $ (267 ) $  

Badger Creek Limited

    749     1,948     2,477  

Orlando Cogen, LP

    2,031     3,152     2,920  

Topsham Hydro Assets

    (436 )   1,506     2,064  

Onondaga Renewables, LLC

    (320 )   (600 )    

Koma Kulshan Associates

    452     458     580  

Chambers Cogen, LP

    13,144     6,599     16,250  

Delta-Person, LP

        (644 )   (1,076 )

Idaho Wind Partners 1, LLC

    (126 )        

Rumford Cogeneration, LP

    (359 )   (1,904 )   2,922  

Selkirk Cogen Partners, LP

    (3,454 )   (280 )   (6,958 )

Gregory Power Partners, LP

    2,162     1,791     4,621  

Mid-Georgia Cogen, LP

        (2,686 )   (2,068 )

Other

        (559 )   (19,837 )
               

Total

    13,777     8,514     1,895  

Distributions from equity method investments

    (16,843 )   (27,884 )   (41,031 )
               

Equity in earnings (loss) of unconsolidated affiliates, net of distributions

  $ (3,066 ) $ (19,370 ) $ (39,136 )
               

Schedule I-110


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Equity method investments (Continued)

        The following summarizes the balance sheets at December 31, 2010, 2009 and 2008, and operating results for each of the years ended December 31, 2010, 2009 and 2008, respectively, for our proportional ownership interest in equity method investments:

 
  2010   2009   2008  

Assets

                   
 

Current assets

                   
   

Chambers

  $ 11,391   $ 10,356   $ 14,418  
   

Mid-Georgia

            13,967  
   

Badger Creek

    2,714     2,567     3,175  
   

Gregory

    3,063     11,358     5,766  
   

Orlando

    6,965     6,725     9,366  
   

Selkirk

    11,782     9,431     11,722  
   

Other

    7,563     2,043     8,489  
 

Non-Current assets

                   
   

Chambers

    253,388     259,989     266,686  
   

Mid-Georgia

            53,706  
   

Badger Creek

    6,645     9,177     10,481  
   

Gregory

    19,490     12,351     21,323  
   

Orlando

    29,419     34,975     40,026  
   

Selkirk

    65,036     78,748     89,110  
   

Other

    128,763     34,631     37,229  
               

  $ 546,219   $ 472,351   $ 585,464  
               

Liabilities

                   
 

Current liabilities

                   
   

Chambers

  $ 15,914   $ 16,898   $ 16,692  
   

Mid-Georgia

            3,938  
   

Badger Creek

    1,520     1,795     1,980  
   

Gregory

    3,421     4,118     3,525  
   

Orlando

    4,841     5,313     3,482  
   

Selkirk

    17,371     13,495     13,727  
   

Other

    76,910     1,704     3,443  
 

Non-Current liabilities

                   
   

Chambers

    109,010     123,946     140,381  
   

Mid-Georgia

            48,394  
   

Badger Creek

             
   

Gregory

    15,470     16,660     20,183  
   

Orlando

             
   

Selkirk

    5,872     17,654     26,798  
   

Other

    1,085     11,538     15,146  
               

  $ 251,414   $ 213,121   $ 297,689  
               

Schedule I-111


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Equity method investments (Continued)

 

 
  2010   2009   2008  

Operating results

                   

Revenue

                   
 

Chambers

  $ 55,469   $ 50,745   $ 68,893  
 

Mid-Georgia

        6,521     14,992  
 

Badger Creek

    13,485     12,861     20,502  
 

Gregory

    31,291     28,477     57,434  
 

Orlando

    42,062     41,911     34,372  
 

Selkirk

    51,915     47,577     71,641  
 

Other

    3,501     23,327     27,566  
               

    197,723     211,419     295,400  

Project expenses

                   
 

Chambers

    38,377     40,540     44,264  
 

Mid-Georgia

        6,519     13,509  
 

Badger Creek

    11,723     10,897     18,021  
 

Gregory

    27,324     24,893     53,101  
 

Orlando

    39,898     38,694     31,819  
 

Selkirk

    48,496     44,045     64,087  
 

Other

    2,049     22,560     25,436  
               

    167,867     188,148     250,237  

Project other income (expense)

                   
 

Chambers

    (3,948 )   (3,606 )   (8,379 )
 

Mid-Georgia

        13,137     (3,551 )
 

Badger Creek

    (1,013 )   (16 )   (4 )
 

Gregory

    (1,805 )   (1,793 )   288  
 

Orlando

    (133 )   (65 )   367  
 

Selkirk

    (6,873 )   (3,812 )   (14,512 )
 

Other

    (2,307 )   (4,822 )   (17,477 )
               

    (16,079 )   (977 )   (43,268 )

Project income (loss)

                   
 

Chambers

  $ 13,144   $ 6,599   $ 16,250  
 

Mid-Georgia

        13,139     (2,068 )
 

Badger Creek

    749     1,948     2,477  
 

Gregory

    2,162     1,791     4,621  
 

Orlando

    2,031     3,152     2,920  
 

Selkirk

    (3,454 )   (280 )   (6,958 )
 

Other

    (855 )   (4,055 )   (15,347 )
               

  $ 13,777   $ 22,294   $ 1,895  
               

Schedule I-112


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Property, plant and equipment

 
  2010   2009   Depreciable
Lives

Land

  $ 3,321   $ 2,081    

Office equipment, machinery and other

    8,040     6,331   3 - 10 years

Leasehold improvements

    2,810     2,411   7 - 15 years

Plant in service

    353,002     257,566   1 - 30 years
             

    367,173     268,389    

Less accumulated depreciation

    (91,752 )   (74,567 )  
             

  $ 275,421   $ 193,822    
             

        Depreciation expense of $11.1 million, $11.1 million and $6.6 million was recorded for the years ended December 31, 2010, 2009 and 2008, respectively.

6. Other intangible assets and transmission system rights

        Other intangible assets include power purchase agreements that are not separately recorded as financial instruments, fuel supply agreements and development costs. Transmission system rights represent the long-term right to approximately 72% of the regulated revenues of the Path 15 transmission line.

        The following tables summarize the components of our intangible assets subject to amortization for the years ended December 31, 2010 and 2009:

 
  Transmission
System Rights
  Power Purchase
Agreements
  Fuel Supply
Agreements
  Development
Costs
  Total  

Gross balances, December 31, 2010

  $ 231,669   $ 110,470   $ 33,845   $ 1,147   $ 377,131  

Less: accumulated amortization

    (43,535 )   (39,190 )   (17,810 )       (100,535 )
                       

Net carrying amount, December 31, 2010

  $ 188,134   $ 71,280   $ 16,035   $ 1,147   $ 276,596  
                       

 

 
  Transmission
System Rights
  Power Purchase
Agreements
  Fuel Supply
Agreements
  Total  

Gross balances, December 31, 2009

  $ 231,669   $ 73,880   $ 43,258   $ 348,807  

Less: accumulated amortization

    (35,685 )   (26,608 )   (18,760 )   (81,053 )
                   

Net carrying amount, December 31, 2009

  $ 195,984   $ 47,272   $ 24,498   $ 267,754  
                   

        The following table presents amortization of intangible assets for the years ended December 31, 2010, 2009 and 2008:

 
  2010   2009   2008  

Transmission system rights

  $ 7,849   $ 7,849   $ 7,506  

Power purchase agreements

    12,411     12,406     4,206  

Fuel supply agreements

    8,461     9,468     2,940  
               

Total amortization

  $ 28,721   $ 29,723   $ 14,652  
               

Schedule I-113


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Other intangible assets and transmission system rights (Continued)

        The following table presents estimated future amortization for the next five years related to our transmission system rights, purchase power agreements and fuel supply agreements:

Year Ended December 31,
  Transmission
System Rights
  Power Purchase
Agreements
  Fuel Supply
Agreements
  Total  

2011

  $ 7,849   $ 14,452   $ 8,461   $ 30,762  

2012

    7,849     14,452     7,574     29,875  

2013

    7,849     12,080         19,929  

2014

    7,849     2,041         9,890  

2015

    7,849     2,041         9,890  

7. Credit facility

        We maintain a credit facility with a capacity of $100.0 million, $50.0 million of which may be utilized for letters of credit. The credit facility matures in August 2012.

        In November 2008, we borrowed $55.0 million under the credit facility and used the proceeds to partially fund the acquisition of Auburndale. We executed an interest rate swap to fix the interest rate at 2.4% through November 2011 for $40.0 million of the balance outstanding under this borrowing. During 2009, the outstanding borrowings under the credit facility were repaid with cash on hand and the interest rate swap was terminated. The remaining amount in accumulated other comprehensive income for this swap was recorded as interest expense in the consolidated statement of operations.

        In June 2010, we borrowed $20.0 million under the credit facility and used the proceeds to partially fund the acquisition of Idaho Wind in July 2010. In October 2010, we repaid the $20.0 million borrowing with proceeds from our common stock and convertible debt offerings.

        The credit facility bears interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin between 1.50% and 3.25% that varies based on certain credit statistics of one of our subsidiaries. As of December 31, 2010, the applicable margin was 1.5% (1.5% in 2009). As of December 31, 2010, $48.6 million of the credit facility capacity was allocated, but not drawn, to support letters of credit for contractual credit support at several of our projects.

        We must meet certain financial covenants under the terms of the credit facility, which are generally based on our cash flow coverage ratio and indebtedness ratios and also require us to report indebtedness ratios to the bank. The facility is secured by pledges of assets and interests in certain subsidiaries. We expect to remain in compliance with the covenants of the credit facility for at least the next 12 months.

8. Long-term debt

        Long-term debt represents project-level long-term debt of our consolidated subsidiaries and the unamortized balance of purchase accounting adjustments that were recorded in connection with the Path 15 acquisition in order to adjust the debt to its fair value on the acquisition date. Project debt is non-recourse to Atlantic Power and generally amortizes during the term of the respective revenue generating contracts of the projects.

Schedule I-114


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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Long-term debt (Continued)

 
  December 31,
2010
  December 31,
2009
 

Project debt, interest rates ranging from 5.1% to 9.0% maturing through 2028

  $ 254,581   $ 230,331  

Purchase accounting fair value adjustments

    11,305     12,030  

Less: current portion of long-term debt

    (21,587 )   (18,280 )
           

Long-term debt

  $ 244,299   $ 224,081  
           

        Principal payments due in the next five years and thereafter are as follows:

2011

  $ 21,587  

2012

    20,958  

2013

    19,702  

2014

    15,065  

2015

    16,999  

Thereafter

    160,270  
       

  $ 254,581  
       

        All of the debt in the table above is represented by non-recourse debt of the projects. Project-level debt is secured by the respective project and its contracts with no other recourse to us. The loans have certain financial covenants that must be met. At December 31, 2010, all of our projects were in compliance with the covenants contained in project-level debt. However, our Epsilon Power Partners, Gregory, Selkirk and Delta-Person projects had not achieved the levels of debt service coverage ratios required by the project-level debt arrangements as a condition to make distributions and were therefore restricted from making distributions to us.

        The required coverage ratio at Epsilon Power Partners is calculated based on the most recent four quarters cash flow results from Chambers. Reduced cash flows resulted in the project not meeting cash flow coverage ratio tests in its non-recourse debt, so we received no distributions from Chambers in 2009 and in the first nine months of 2010. The Chambers project began to meet the cash flow coverage ratio for its non-recourse debt again as of September 30, 2010 and the project distributed $2.8 million to our project holding company, Epsilon Power Partners in October 2010. However, the required cash flow coverage ratio on the debt at Epsilon Power Partners has not been achieved and, as a result, Epsilon has not made any distributions to the Company during 2009 and 2010. Based on our current projections, Epsilon will continue receiving distributions from the project in 2011 based on meeting the required debt service coverage ratios and we expect Epsilon to resume making distributions to the Company in late 2011.

        The required coverage ratio at Selkirk is calculated based on both historical project cash flows for the previous six months, as well as projected project cash flows for the next six months. Increased natural gas transportation costs attributable to a contractual price increase at Selkirk are the primary contributors to the project not currently meeting its minimum coverage ratio.

        The required coverage ratio at Delta-Person is based on the most recent four-quarter period. In 2009, Delta-Person incurred higher than anticipated operations and maintenance costs due to an unanticipated repair. The higher operations and maintenance costs caused Delta-Person to fail its debt service coverage ratio and restrict cash distributions for 2010.

Schedule I-115


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Long-term debt (Continued)

        The required coverage ratio at Gregory is calculated based on both historical project cash flows for the previous six months, as well as projected cash flows for the next six months. Increased fuel costs in 2011 attributable to fuel hedges expiring at the end of 2010 are the primary contributors to the project not currently meeting its debt service coverage ratio requirements.

        As at December 31, 2010, the amount of restricted net assets of our unconsolidated subsidiaries that may not be distributed to us in the form of a dividend is approximately $298.4 million and the amount of undistributed earnings of unconsolidated subsidiaries was approximately $151.3 million. Project-level debt is secured by the respective projects and their contracts with no other recourse to us. At December 31, 2010, all of our projects were in compliance with the covenants contained in project-level debt agreements.

9. Subordinated notes

        On November 27, 2009 our shareholders approved a conversion from the IPS structure to a traditional common share structure. Each IPS has been exchanged for one new common share of Atlantic Power and each old common share that did not form part of an IPS was exchanged for approximately 0.44 of a new common share. This transaction resulted in the extinguishment of Cdn$347.8 million ($327.7 million) principal value of subordinated notes.

        A loss on the common share conversion in the amount of $13.1 million was recorded in interest expense within administrative and other expenses and was comprised of the write off of unamortized deferred financing costs of $7.5 million, the costs associated with the common share conversion of $4.7 million and the write off of the unamortized subordinated note premium of $0.9 million.

        On December 17, 2009, we exercised our subordinated note call option to redeem the remaining Cdn$40.7 million ($38.7 million) principal value of Subordinated Notes at 105% of the principal amount. A loss on the redemption of the subordinated notes in the amount of $3.1 million was recorded in interest expense within administrative and other expenses and was comprised of the write off of unamortized deferred financing costs of $1.2 million and the 5% premium paid in the amount of $1.9 million.

        The subordinated notes were due to mature in November 2016 subject to redemption under specified conditions at the option of Atlantic Power, commencing on or after November 18, 2009. Interest was payable monthly in arrears at an annual rate of 11% and the principal repayment was to occur at maturity.

        The subordinated notes were denominated in Canadian dollars and were secured by a subordinated pledge of our interest in certain subsidiaries, and contained certain restrictive covenants. Cdn$39.5 million principal value of the subordinated notes were separately held by two investors and the remaining amount of the outstanding subordinated notes formed a part of our publicly traded IPSs.

        Interest expense related to the subordinated notes was $36.4 million and $40.2 million for the years ended December 31, 2009 and 2008, respectively.

10. Convertible debentures

        In 2006 we issued, in a public offering, Cdn$60 million aggregate principal amount of 6.25% convertible secured debentures (the "2006 Debentures") for gross proceeds of $52.8 million. The 2006 Debentures pay interest semi-annually on April 30 and October 31 of each year. The 2006 Debentures had an initial maturity date of October 31, 2011 and are convertible into approximately 80.6452

Schedule I-116


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Convertible debentures (Continued)


common shares per Cdn$1,000 principal amount of 2006 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per common share.

        In connection with the common share conversion on November 27, 2009, the holders of the 2006 Debentures approved an amendment to increase the annual interest rate from 6.25% to 6.50% and separately, an extension of the maturity date from October 2011 to October 2014.

        During 2010, Cdn$4.2 million of the 2006 Debentures were converted to 338,627 common shares. As of December 31, 2010 the 2006 Debentures balance is Cdn$55.8 million ($56.1 million).

        On December 17, 2009, we issued, in a public offering, Cdn$86.3 million aggregate principal amount of 6.25% convertible unsecured debentures (the "2009 Debentures") for gross proceeds of $82.1 million. The 2009 Debentures pay interest semi-annually on March 15 and September 15 of each year beginning on September 15, 2010. The 2009 Debentures mature on March 15, 2017 and are convertible into approximately 76.9231 common shares per Cdn$1,000 principal amount of 2009 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$13.00 per common share.

        During 2010, Cdn$3.1 million of the 2009 Debentures were converted to 240,458 common shares. As of December 31, 2010 the 2009 Debentures balance is Cdn$83.1 million ($83.6 million).

        On October 20, 2010, we issued, in a public offering, Cdn$80.5 million aggregate principal amount of 5.60% convertible unsecured subordinated debentures (the "2010 Debentures") for gross proceeds of $78.9 million. The 2010 Debentures pay interest semi-annually on June 30 and December 30 of each year beginning June 30, 2011. The 2010 Debentures mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion rate of 55.2486 common shares per Cdn$1,000 principal amount of 2010 Debentures, at any time, at the option of the holder, representing an initial conversion price of approximately Cdn$18.10 per common share. As of December 31, 2010 the 2010 Debentures balance is Cdn$80.5 million ($80.9 million).

        Aggregate interest expense related to the 2006, 2009 and 2010 Debentures was $9.9 million, $3.5 million and $3.5 million for the years ended December 31, 2010, 2009 and 2008, respectively.

11. Fair value of financial instruments

        The estimated carrying values and fair values of our recorded financial instruments related to operations are as follows:

 
  2010   2009  
 
  Carrying
Amount
  Fair Value   Carrying
Amount
  Fair Value  

Cash and cash equivalents

  $ 45,497   $ 45,497   $ 49,850   $ 49,850  

Restricted cash

    15,744     15,744     14,859     14,859  

Derivative assets current

    8,865     8,865     5,619     5,619  

Derivative assets non-current

    17,884     17,884     14,289     14,289  

Derivative liabilities current

    10,009     10,009     6,512     6,512  

Derivative liabilities non-current

    21,543     21,543     5,513     5,513  

Long-term debt, including current portion

    265,886     281,491     242,361     267,765  

Convertible debentures

    220,616     242,316     139,153     141,251  

Schedule I-117


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Fair value of financial instruments (Continued)

        Our financial instruments that are recorded at fair value have been classified into levels using a fair value hierarchy.

        The three levels of the fair value hierarchy are defined below:

        The following represents the recurring measurements of fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of December 31, 2010 and December 31, 2009. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

 
  December 31, 2010  
 
  Level 1   Level 2   Level 3   Total  

Assets:

                         
 

Cash and cash equivalents

  $ 45,497   $   $   $ 45,497  
 

Restricted cash

    15,744             15,744  
 

Derivative instruments asset

        26,749         26,749  
                   
 

Total

  $ 61,241   $ 26,749   $   $ 87,990  
                   

Liabilities:

                         
 

Derivative instruments liability

  $   $ 31,552   $   $ 31,552  
                   
 

Total

  $   $ 31,552   $   $ 31,552  
                   

 

 
  December 31, 2009  
 
  Level 1   Level 2   Level 3   Total  

Assets:

                         
 

Cash and cash equivalents

  $ 49,850   $   $   $ 49,850  
 

Restricted cash

    14,859             14,859  
 

Derivative instruments asset

        19,908         19,908  
                   
 

Total

  $ 64,709   $ 19,908   $   $ 84,617  
                   

Liabilities:

                         
 

Derivative instruments liability

  $   $ 12,025   $   $ 12,025  
                   
 

Total

  $   $ 12,025   $   $ 12,025  
                   

        The fair value of our derivative instruments are based on price quotes from brokers in active markets who regularly facilitate those transactions and we believe such price quotes are executable. We

Schedule I-118


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Fair value of financial instruments (Continued)


adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating or the credit rating of our counterparties. As of December 31, 2010, the credit reserve resulted in a $0.6 million net increase in fair value, which is comprised of a $0.2 million pre-tax gain in other comprehensive income and a $0.5 million gain in change in fair value of derivative instruments offset by a $0.1 million loss in foreign exchange. As of December 31, 2009, the credit reserve resulted in a $0.1 million increase in fair value which is comprised of a $0.1 million gain in OCI and a $0.3 million gain in change in fair value of derivative instruments and a $0.3 million loss in foreign exchange.

        The carrying amounts for cash and cash equivalents and restricted cash approximate fair value due to their short-term nature. The fair value of long-term debt, subordinated notes and convertible debentures was determined using quoted market prices, as well as discounting the remaining contractual cash flows using a rate at which we could issue debt with a similar maturity as of the balance sheet date.

        As of December 31, 2007, approximately $26 million of our cash and cash equivalents were invested in auction-rate securities ("ARSs"). ARSs typically have an underlying maturity of up to 40 years but have historically traded in seven or 28 day intervals in a highly liquid market. The ARSs that were held at December 31, 2007 were redeemed at auctions held in January 2008 and the proceeds were re-invested in ARSs.

        In early 2008, the overall market for ARSs suffered a significant decline in liquidity and most of the auctions of ARSs were unsuccessful, resulting in our continuing to hold these securities and the issuers paying interest at the maximum contractual rate. In September and November 2008, all of our investments in ARSs were sold at par plus accrued interest for $36.5 million. Purchases and sales of ARSs are presented gross in the consolidated statements of cash flows because they are classified as available-for-sale securities.

Schedule I-119


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Accounting for derivative instruments and hedging activities

        We have elected to disclose derivative instruments assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:

 
  December 31, 2010  
 
  Derivative
Assets
  Derivative
Liabilities
 

Derivative instruments designated as cash flow hedges:

             
 

Interest rate swap current

  $   $ 2,124  
 

Interest rate swap long-term

        2,626  
           

Total derivative instruments designated as cash flow hedges

        4,750  
           

Derivative instruments not designated as cash flow hedges:

             
 

Interest rate swap current

        1,286  
 

Interest rate swap long-term

    3,299     2,000  
 

Foreign currency forward contracts current

    8,865      
 

Foreign currency forward contracts long-term

    14,585      
 

Natural gas swap current

        6,599  
 

Natural gas swap long-term

        16,917  
           

Total derivative instruments not designated as cash flow hedges

    26,749     26,802  
           

Total derivative instruments

  $ 26,749   $ 31,552  
           

 

 
  December 31, 2009  
 
  Derivative
Assets
  Derivative
Liabilities
 

Derivative instruments designated as cash flow hedges:

             
 

Interest rate swap current

  $   $ 726  
 

Interest rate swap long-term

        167  
           

Total derivative instruments designated as cash flow hedges

        893  
           

Derivative instruments not designated as cash flow hedges:

             
 

Interest rate swap current

        1,705  
 

Interest rate swap long-term

        1,707  
 

Foreign currency forward contracts current

    5,619      
 

Foreign currency forward contracts long-term

    14,289      
 

Natural gas swap current

    95     4,174  
 

Natural gas swap long-term

    14     3,655  
           

Total derivative instruments not designated as cash flow hedges

    20,017     11,241  
           

Total derivative instruments

  $ 20,017   $ 12,134  
           

Schedule I-120


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Accounting for derivative instruments and hedging activities (Continued)

Natural gas swaps

        The Lake project's operating margin is exposed to changes in natural gas spot market prices from the expiration of its natural gas supply contract on June 30, 2009 through the expiration of its PPA on July 31, 2013. The Auburndale project purchases natural gas under a fuel supply agreement which provides approximately 80% of the project's fuel requirements at fixed prices through June 30, 2012. The remaining 20% is purchased at spot market prices and therefore the project is exposed to changes in natural gas prices for that portion of its gas requirements through the termination of the fuel supply agreement and 100% of its natural gas requirements from the expiry of the fuel supply agreement in mid-2012 until the termination of its PPA at the end of 2013.

        The Orlando project's operating margin is exposed to changes in natural gas spot market prices from the expiration of its gas supply agreement in 2013 until its PPA expires in 2023. In October 2010, we executed two fuel swap agreements which become effective on January 1, 2014 and January 1, 2015 and terminate on December 31, 2014 and 2015, respectively. These swap agreements were entered into at Atlantic Power Corporation and not at the project level. Orlando is accounted for under the equity method of accounting.

        Our strategy to mitigate the future exposure to changes in natural gas prices at Lake, Auburndale and Orlando consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheet at fair value.

        Changes in the fair value of the natural gas swaps related to Lake and Auburndale through June 30, 2009 were recorded in other comprehensive income (loss) as they were designated as a hedge of the risk associated with changes in market prices of natural gas. As of July 1, 2009, we de-designated these natural gas swap hedges and the changes in their fair value subsequent to July 1, 2009 are now recorded in change in fair value of derivative instruments in the consolidated statements of operations. Amounts in accumulated other comprehensive income (loss) remaining prior to de-designation are amortized into the consolidated statements of operations over the remaining term of the natural gas swaps.

        We have executed an interest rate swap at our consolidated Auburndale project to economically fix a portion of its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Auburndale debt agreement. The interest rate swap was executed in November 2009 and expires on November 30, 2013.

        The interest rate swap is a derivative financial instrument designated as a cash flow hedge and is recorded in the balance sheet at fair value. Changes in the fair value of the interest rate swap are recorded in accumulated other comprehensive income (loss) and reclassified to interest expense when settled in cash. This swap agreement is effective November 2009 through November 2013.

        In February 2008, Cadillac entered into an interest rate swap agreement that effectively fixed the interest rate at 5.90% from February 20, 2008 to February 15, 2011, 6.02% from February 16, 2011 to February 15, 2015, 6.14% from February 16, 2015 to February 15, 2019, 6.26% from February 16, 2019 to February 15, 2023, and 6.38% thereafter. The notional amount of the interest rate swap agreement

Schedule I-121


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Accounting for derivative instruments and hedging activities (Continued)


mirrors the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies and is designated as a cash flow hedge, is effective through June 2025.

        We executed two interest rate swaps at our consolidated Piedmont project to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements are not designated as hedges and changes in their fair market value are recorded in the consolidated statements of operations. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively.

        Unrealized gains on interest rate swaps designated as cash flow hedges, net of tax, have been recorded in the consolidated statements of shareholders' equity as a gain in other comprehensive income of $0.4 million, $0.6 million and $0.5 million for the years ended December 31, 2010, 2009 and 2008, respectively. Realized losses on these interest rate swaps of $0.5 million, $0.5 million and $0.0 million were recorded in interest expense, net for the years ended December 31, 2010, 2009 and 2008, respectively.

        Unrealized gains and losses on natural gas swaps previously designated as cash flow hedges are recorded in other comprehensive income. In the period in which the unrealized gains and losses are settled, the cash settlement payments are recorded as fuel expense. Other comprehensive loss recorded for natural gas swap contracts accounted for as cash flow hedges totaled $5.1 million, net of tax, prior to July 1, 2009 when hedge accounting for these natural gas swaps was discontinued prospectively. Amortization of the loss of $1.0 million and $4.3 million, net of tax, was recorded in change in fair value of derivative instruments for the years ended December 31, 2010 and 2009, respectively.

        Unrealized gains and losses on derivative instruments not designated as cash flow hedges are recorded in change in fair value of derivative instruments in the consolidated statements of operations.

        The following table summarizes realized gains and losses for derivative instruments not designated as cash flow hedges:

 
  Classification of (gain) loss
recognized in income
  2010   2009  

Natural gas swaps

  Fuel   $ 9,141   $ 10,089  

Foreign currency forwards

  Foreign exchange gain     (6,625 )   (3,864 )

Interest rate swaps

  Interest, net     1,664     1,446  

        Unrealized gains and losses associated with changes in the fair value of derivative instruments not designated as cash flow hedges and ineffectiveness of derivatives designated as cash flow hedges are reflected in current period earnings. The following table summarizes the pre-tax (gains) and losses

Schedule I-122


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Accounting for derivative instruments and hedging activities (Continued)


resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:

 
  2010   2009   2008  

Change in fair value of derivative instruments:

                   
 

Interest rate swaps

  $ (3,423 ) $ 369   $ (1,804 )
 

Indexed swap and hedge

            (10,844 )
 

Natural gas swaps

    17,470     (7,182 )   (3,378 )
               

  $ 14,047   $ (6,813 ) $ (16,026 )
               

        We entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the normal purchases and normal sales exception as of December 31, 2010:

 
  Units   December 31,
2010
 

Interest rate swaps

  Interest (US$)   $ 44,228  

Currency forwards

  Dollars (Cdn$)   $ 219,800  

Natural gas swaps

  Natural Gas (Mmbtu)     15,540  

        We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as we generate cash flow in U.S. dollars but pay dividends to shareholders and interest on convertible debentures predominantly in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on the long-term sustainability of dividends to shareholders. We have executed this strategy by entering into forward contracts to purchase Canadian dollars at a fixed rate to hedge approximately 86% of our expected dividend and convertible debenture interest payments through 2013. Changes in the fair value of the forward contracts partially offset foreign exchange gain or losses on the U.S. dollar equivalent of our Canadian dollar obligations. The forward contracts consist of (1) monthly purchases through the end of 2013 of Cdn$6.0 million at an exchange rate of Cdn$1.134 per U.S. dollar and (2) purchases in both April and October 2011 of Cdn$1.9 million at an exchange rate of Cdn$1.1075 per U.S. dollar.

        It is our intention to periodically consider extending the length of these forward contracts. In addition, we will consider executing additional foreign currency forward contracts to hedge expected additional dividend and interest payments associated with the common shares and convertible debentures issued in our October 2010 public offering (see Note 10 and Note 18).

        The foreign exchange forward contracts are recorded at estimated fair value based on quoted market prices and our estimation of the counterparty's credit risk. The fair value of our forward foreign currency contracts is $23.4 million and $19.9 million for the years ended December 31, 2010 and 2009, respectively. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations.

Schedule I-123


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Accounting for derivative instruments and hedging activities (Continued)

        The following table contains the components of recorded foreign exchange (gain) loss for the years ended December 31, 2010, 2009 and 2008:

 
  2010   2009   2008  

Unrealized foreign exchange (gain) loss:

                   
 

Subordinated notes and convertible debentures

  $ 9,153   $ 55,508   $ (85,212 )
 

Forward contracts and other

    (3,542 )   (31,138 )   46,009  
               

    5,611     24,370     (39,203 )

Realized foreign exchange gains on forward contract settlements

    (6,625 )   (3,864 )   (8,044 )
               

  $ (1,014 ) $ 20,506   $ (47,247 )
               

        The following table illustrates the impact on the fair value of our financial instruments of a 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar as of December 31, 2010:

Convertible debentures

  $ 22,062  

Foreign currency forward contracts

  $ (23,893 )

        The following tables summarize the changes in the accumulated other comprehensive income (loss) ("OCI") balance attributable to derivative financial instruments designated as a hedge, net of tax:

Year ended December 31, 2010
  Interest Rate
Swaps
  Natural Gas
Swaps
  Total  

Accumulated OCI balance at December 31, 2009

  $ (538 ) $ (321 ) $ (859 )

Change in fair value of cash flow hedges

    (360 )       (360 )

Realized from OCI during the period

    471     1,003     1,474  
               

Accumulated OCI balance at December 31, 2010

  $ (427 ) $ 682   $ 255  
               

 

Year ended December 31, 2009
  Interest Rate
Swaps
  Natural Gas
Swaps
  Total  

Accumulated OCI balance at December 31, 2008

  $ (501 ) $ (2,635 ) $ (3,136 )

Change in fair value of cash flow hedges

    (565 )   (1,985 )   (2,550 )

Realized from OCI during the period

    528     4,299     4,827  
               

Accumulated OCI balance at December 31, 2009

  $ (538 ) $ (321 ) $ (859 )
               

13. Income taxes

 
  2010   2009   2008  

Current income tax expense (benefit)

  $ 960   $ (9,257 ) $ 449  

Deferred tax expense (benefit)

    17,964     (6,436 )   (14,009 )
               

Total income tax expense (benefit)

  $ 18,924   $ (15,693 ) $ (13,560 )
               

Schedule I-124


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Income taxes (Continued)

        The following is a reconciliation of income taxes calculated at the Canadian enacted statutory rate of 28.5%, 30.0% and 33.5% at December 31, 2010, 2009 and 2008, respectively, to the provision for income taxes in the consolidated statements of operations:

 
  2010   2009   2008  

Computed income taxes at Canadian statutory rate

  $ 4,295   $ (16,254 ) $ 11,571  

Increases (decreases) resulting from:

                   
 

Operating countries with different income tax rates

    1,537     (5,418 )   2,245  
               

  $ 5,832   $ (21,672 ) $ 13,816  

Valuation allowance

    12,289     22,005     (37,111 )
               

    18,121     333     (23,295 )

Dividend withholding tax

   
765
   
   
 

Permanent differences

        (1,131 )   10,787  

Canadian loss carryforwards

        (13,204 )   (2,787 )

Branch profits tax

            2,368  

Prior year true-up

        (1,970 )   (841 )

Other

    38     279     208  
               

    803     (16,026 )   9,735  
               

  $ 18,924   $ (15,693 ) $ (13,560 )
               

        The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2010 and 2009 are presented below:

 
  2010   2009  

Deferred tax assets:

             
 

Intangible assets

  $ 37,488   $ 45,237  
 

Loss carryforwards

    58,702     62,926  
 

Other accrued liabilities

    18,869     16,212  
 

IPS and issuance costs

    2,312     1,374  
 

Natural gas and interest rate hedges

        573  
 

Other

    130      
           
 

Total deferred tax assets

    117,501     126,322  
 

Valuations allowance

    (79,420 )   (67,131 )
           

    38,081     59,191  

Deferred tax liabilities:

             
 

Property, plant and equipment

    (66,535 )   (69,639 )
 

Natural gas and interest rate hedges

    (170 )    
 

Unrealized foreign exchange gain

    (815 )   (284 )
           
 

Total deferred tax liabilities

    (67,520 )   (69,923 )
           

Net deferred tax liability

  $ (29,439 ) $ (10,732 )
           

Schedule I-125


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Income taxes (Continued)

        The following table summarizes the net deferred tax position as of December 31, 2010 and 2009:

 
  2010   2009  

Current deferred tax assets

  $   $ 17,887  

Long-term deferred tax liabilities

    (29,439 )   (28,619 )
           

Net deferred tax asset (liability)

  $ (29,439 ) $ (10,732 )
           

        As of December 31, 2010, we have recorded a valuation allowance of $79.4 million. This amount is comprised primarily of provisions against available Canadian and U.S. net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

        As of December 31, 2010, we had the following net operating loss carryforwards that are scheduled to expire in the following years:

2026

  $ 37,525  

2027

    45,960  

2028

    44,176  

2029

    59,930  

2030

    2,596  
       

  $ 190,187  
       

Schedule I-126


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. Long-Term Incentive Plan

        The following table summarizes the changes in outstanding LTIP notional units during the years ended December 31, 2010, 2009 and 2008:

 
  Units   Grant Date
Weighted-Average
Fair Value per Unit
 

Outstanding at December 31, 2007

    179,028   $ 9.43  

Granted

    142,717     9.99  

Additional shares from dividends

    28,138     9.71  

Forfeited

    (37,944 )   9.43  

Vested

    (48,346 )   9.43  
           

Outstanding at December 31, 2008

    263,593     9.76  

Granted

    267,408     5.76  

Additional shares from dividends

    49,540     7.80  

Vested

    (109,260 )   9.71  
           

Outstanding at December 31, 2009

    471,281     7.30  

Granted

    305,112     13.29  

Additional shares from dividends

    46,854     9.54  

Vested

    (222,265 )   7.94  
           

Outstanding at December 31, 2010

    600,981   $ 10.28  
           

        In the second quarter of 2010, the Board of Directors approved an amendment to the LTIP. The amended LTIP will be effective for grants beginning with the 2010 performance year. Under the amended LTIP, the notional units granted to plan participants will have the same characteristics as notional units under the old LTIP. However, the number of notional units that vest will be based, in part, on the total shareholder return of Atlantic Power compared to a group of peer companies in Canada. In addition, vesting of the notional units for officers of Atlantic Power will occur on a three year cliff basis as opposed to ratable vesting over three years for grants made prior to the amendment.

        Vested notional units are expected to be redeemed one-third in cash and two-thirds in shares of our common stock. Notional units granted that are expected to be redeemed in cash upon vesting are accounted for as liability awards. Notional units granted that are expected to be redeemed in common shares upon vesting are accounted for as equity awards. Notional units granted prior to the 2010 performance period are subject to the vesting conditions of the LTIP before the amendments made in 2010. We reclassified the portion of outstanding awards expected to vest in common shares totaling $1.4 million from accounts payable and accrued liabilities and other non-current liabilities to common shares as of June 29, 2010, the date the amended LTIP was approved by our shareholders.

        On March 29, 2010, our board of directors approved the grant of 138,892 notional LTIP units for the 2009 performance period under the terms of the LTIP before the 2010 amendments. In May 2010, our board of directors approved the initial grant of 83,110 notional LTIP units for executive officers under the amended LTIP for the 2010-2012 performance period, subject to final shareholder approval of the amended LTIP, which occurred on June 29, 2010. Also in May 2010 and subject to the final shareholder approval of the amended LTIP, our board of directors granted transition awards to our executive officers consisting of an additional 83,110 notional LTIP units. The transition awards are designed to mitigate the impact of the changes in vesting provisions of the LTIP from a ratable vesting

Schedule I-127


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. Long-Term Incentive Plan (Continued)


over three years to cliff vesting at the end of three years. The transition awards are subject to the performance measurement and other provisions of the amended LTIP, except that one-third of the transition awards vest in the first quarter of 2011 and the other two-thirds vest in the first quarter of 2012.

        The notional units, other than the transition awards, granted under the amended LTIP cliff-vest three years after the grant date. The final number of notional units that will vest, if any, at the end of the three year vesting period will be based on our achievement of target levels of relative total shareholder return, which is the change in the value of an investment in our common stock, including reinvestment of dividends, compared to that of a peer group of companies during the performance period. The total number of notional units vesting will range from zero up to a maximum 150% of the number of notional units in the executives' accounts on the vesting date for that award, depending on the level of achievement of relative total shareholder return during the measurement period.

        Compensation expense related to awards granted to participants in the LTIP is recorded over the vesting period based on the estimated fair value of the award on the grant date for notional units accounted for as equity awards and the fair value of the award at each balance sheet date for notional units accounted for as liability awards. Fair value of the awards granted prior to the 2010 LTIP amendment is determined by projecting the total number of notional units that will vest in future periods, including dividends received on notional units during the vesting period, and applying the current market price per share to the projected number of notional units that will vest. The fair value of awards granted in 2010 under the amended LTIP with market vesting conditions is based upon a Monte Carlo simulation model on their grant date. Compensation expense is recognized regardless of the relative total shareholder return performance, provided that the LTIP participant remains employed by Atlantic Power Corporation. The fair value of all outstanding notional units under the amended LTIP at December 31, 2010, is approximately $7.8 million. The aggregate number of shares which may be issued from treasury under the amended LTIP is limited to one million. Unvested notional units are recorded as either a liability or equity award based on management's intended method of redeeming the notional units when they vest.

        Both the total shareholder return performance and the fair value of the notional units under the Monte Carlo simulation are determined with the assistance of a third party.

        In calculating the fair value of the awards granted in 2010 under the amended LTIP, the Monte Carlo simulation model utilizes multiple input variables over the performance period in order to determine the likely relative total shareholder return. The Monte Carlo simulation model computed simulated our total shareholder return and for our peer companies during the remaining time in the performance period with the following inputs: (i) stock price on the measurement date; (ii) expected volatility; (iii) risk-free interest rate; (iv) dividend yield; and (v) correlations of historical common stock returns between Atlantic Power Coporation and the peer companies and among the peer companies. Expected volatilities utilized in the Monte Carlo model are based on historical volatility of the Company's and the peer companies' stock prices over a period equal in length to that of the remaining vesting period. The risk free interest rate is derived from the U.S. Treasury yield curve in effect at the time of grant with a term equal to the performance period assumption at the time of grant.

Schedule I-128


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. Long-Term Incentive Plan (Continued)

        The calculation of simulated total shareholder return under the Monte Carlo model for the remaining time in the performance period included the following assumptions:

 
  Year ended
December 31, 2010
 

Weighted average risk free rate of return

    0.71 %

Dividend yield

    9.39 %

Expected volatility—Company

    40.0 %

Expected volatility—peer companies

    25.0 - 55.0 %

Weighted average remaining measurement period

    1.43 years  

15. Basic and diluted earnings (loss) per share

        Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be issued if all of the convertible debentures were converted into shares at January 1, 2010. Dilutive potential shares also include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP.

        Because we reported a loss for the years ended December 31, 2010 and 2009, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.

        The following table sets forth the diluted net income and potentially dilutive shares utilized in the per share calculation for the years ended December 31, 2010, 2009 and 2008:

 
  2010   2009   2008  

Numerator:

                   

Net income (loss) attributable to Atlantic Power Corporation

  $ (3,752 ) $ (38,486 ) $ 48,101  

Add: interest expense for potentially dilutive convertible debentures, net(1)

            382  
               

Diluted net loss attributable to Atlantic Power Corporation

    (3,752 )   (38,486 )   48,483  

(1)
The above adjustment for net interest on the potential common shares that would be issued on the conversion of the convertible debentures has been determined by eliminating the actual interest on the convertible debentures and, for periods prior to our conversion from an IPS to common share structure on November 27, 2009, including the imputed interest on the additional subordinated notes that would be issued on the conversion (the conversion of the debentures is into additional IPSs, each consisting of one common share and Cdn$5.767 principal amount of subordinated notes).

Schedule I-129


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. Basic and diluted earnings (loss) per share (Continued)

 
  2010   2009   2008  

Denominator:

                   

Basic shares outstanding

    61,706     60,632     61,290  

Dilutive potential shares:

                   
 

Convertible debentures

    12,339     5,095     4,839  
 

LTIP notional units

    542     476     221  
               

Potentially dilutive shares

    74,587     66,203     66,350  
               

Diluted EPS

  $ (0.06 ) $ (0.63 ) $ 0.73  
               

        Potentially dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units have been excluded from fully diluted shares in the years ended December 31, 2010 and 2009 because their impact would be anti-dilutive.

16. Segment and related information

        We have six reportable segments: Path 15, Auburndale, Lake, Pasco, Chambers and Other Project Assets.

        We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income less interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are

Schedule I-130


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Segment and related information (Continued)


required to be recorded at fair value. A reconciliation of project income to Project Adjusted EBITDA is included in the table below.

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other
Project
Assets
  Un-allocated
Corporate
  Consolidated  

Year ended December 31, 2010:

                                                 

Operating revenues

  $ 31,000   $ 77,876   $ 74,024   $ 11,305   $   $ 1,051   $   $ 195,256  

Segment assets

    210,733     107,336     112,481     39,241         143,972     399,249     1,013,012  

Capital expenditures

        59     1,642     551         44,323     120     46,695  

Goodwill

    8,918                     3,535         12,453  

Project Adjusted EBITDA

  $ 28,639   $ 34,232   $ 31,428   $ 4,712   $ 19,344   $ 34,229   $   $ 152,584  

Change in fair value of derivative instruments

        8,591     8,731         (1,317 )   1,638         17,643  

Depreciation and amortization

    8,387     19,813     9,097     3,001     3,371     22,122         65,791  

Interest, net

    12,401     1,631     (9 )   (8 )   6,260     3,353         23,628  

Other project (income) expense

                          761     2,882         3,643  
                                   

Project income

    7,851     4,197     13,609     1,719     10,269     4,234         41,879  

Interest, net

                            11,701     11,701  

Administration

                            16,149     16,149  

Foreign exchange gain

                            (1,014 )   (1,014 )

Other income, net

                            (26 )   (26 )

Income from operations before income taxes

    7,851     4,197     13,609     1,719     10,269     4,234     (26,810 )   15,069  

Income tax expense (benefit)

    162                         18,762     18,924  
                                   

Net income

  $ 7,689   $ 4,197   $ 13,609   $ 1,719   $ 10,269   $ 4,234   $ (45,572 ) $ (3,855 )
                                   

 

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other
Project
Assets
  Un-allocated
Corporate
  Consolidated  

Year ended December 31, 2009:

                                                 

Operating revenues

  $ 31,000   $ 74,875   $ 62,285   $ 11,357   $   $   $   $ 179,517  

Segment assets

    219,586     130,053     118,925     42,479             358,533     869,576  

Capital expenditures

        321     1,278     355               62     2,016  

Goodwill

    8,918                             8,918  

Project Adjusted EBITDA

  $ 27,691   $ 35,221   $ 25,378   $ 3,299   $ 13,595   $ 38,995   $   $ 144,179  

Change in fair value of derivative instruments

        2,118     5,064         (2,604 )   469         5,047  

Depreciation and amortization

    8,511     19,780     10,098     2,987     3,390     22,877         67,643  

Interest, net

    12,911     2,833     (4 )       7,674     8,097         31,511  

Other project (income) expense

    (1,230 )           (26 )   1,229     (8,410 )       (8,437 )
                                   

Project income

    7,499     10,490     10,220     338     3,906     15,962         48,415  

Interest, net

                            55,698     55,698  

Administration

                            26,028     26,028  

Foreign exchange gain

                            20,506     20,506  

Other income, net

                            362     362  

Loss from operations before income taxes

    7,499     10,490     10,220     338     3,906     15,962     (102,594 )   (54,179 )

Income tax expense (benefit)

                            (15,693 )   (15,693 )
                                   

Net loss

  $ 7,499   $ 10,490   $ 10,220   $ 338   $ 3,906   $ 15,962   $ (86,901 ) $ (38,486 )
                                   

Schedule I-131


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Segment and related information (Continued)

 

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other
Project
Assets
  Un-allocated
Corporate
  Consolidated  

Year ended December 31, 2008:

                                                 

Operating revenues

  $ 31,528   $ 10,003   $ 61,610   $ 58,897   $   $ 11,774   $   $ 173,812  

Segment assets

    235,198     151,524     130,083     52,925             338,265     907,995  

Capital expenditures

            814     175                 113     1,102  

Goodwill

    8,918                             8,918  

Project Adjusted EBITDA

  $ 28,872   $ 4,461   $ 32,892   $ 21,953   $ 27,603   $ 58,908   $   $ 174,689  

Change in fair value of derivative instruments

                3,378     4,295     22,241         29,914  

Depreciation and amortization

    7,917     2,127     11,232     11,154     2,974     24,721         60,125  

Interest, net

    13,232     225     (32 )   978     8,536     7,377         30,316  

Other project expense

                    580     12,748         13,328  
                                   

Project income

    7,723     2,109     21,692     6,443     11,218     (8,179 )       41,006  

Interest, net

                            43,275     43,275  

Administration

                            10,012     10,012  

Foreign exchange gain

                            (47,247 )   (47,247 )

Other expense, net

                            425     425  

Income from operations before income taxes

    7,723     2,109     21,692     6,443     11,218     (8,179 )   (6,465 )   34,541  

Income tax benefit

                            (13,560 )   (13,560 )
                                   

Net income

  $ 7,723   $ 2,109   $ 21,692   $ 6,443   $ 11,218   $ (8,179 ) $ 7,095   $ 48,101  
                                   

        Progress Energy Florida and the California Independent System Operator ("CAISO") provide for 78.0% and 15.9%, respectively, of total consolidated revenues for the year ended December 31, 2010, 71.1% and 17.3%, respectively, of total consolidated revenues for the year ended December 31, 2009 and 75.1% and 18.1%, respectively, of total consolidated revenues for the year ended December 31, 2008. Progress Energy Florida purchases electricity from Auburndale and Lake, and the CAISO makes payments to Path 15.

17. Related party transactions

        During 2010, we made a short-term $22.8 million loan to Idaho Wind (see Note 3(e)) to provide temporary funding for construction of the project until a portion of the project-level construction financing is completed. Member loans will be paid down with a combination of excess proceeds from the federal stimulus cash grant after repaying the cash grant facility, funds from a third closing for additional debt, and project cash flow. The federal stimulus grant is expected in the second quarter of 2011 and a third closing is expected by the end of the year. The outstanding loans bear interest at a prime rate plus 10% (13.25% as December 31, 2010). As of March 18, 2011, $5.1 million of the loan has been repaid.

        Prior to December 31, 2009, Atlantic Power was managed by Atlantic Power Management, LLC (the "Manager"), which was owned by two private equity funds managed by Arclight Capital Partners, LLC ("ArcLight"). On December 31, 2009, we terminated our management agreements with the Manager and have agreed to pay the ArcLight funds an aggregate of $15 million, to be satisfied by a payment of $6 million that was made at the termination date, and additional payments of $5 million, $3 million and $1 million on the respective first, second and third anniversaries of the termination date. We recorded the remaining liability associated with the termination fee at its estimated fair value of

Schedule I-132


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. Related party transactions (Continued)


$3.7 million at December 31, 2010. The contract termination liability is being accreted to the final amounts due over the term of these payments.

18. Common stock and normal course issuer bid

        On October 20, 2010, we completed a public offering of 6,029,000 common shares, including 784,000 common shares issued pursuant to the exercise in full of the underwriters' over-allotment option, at a price of $13.35 per common share. We received net proceeds from the common share offering, after deducting the underwriters discounts and expenses, of approximately $75.3 million.

        On November 27, 2009 the shareholders approved the conversion from the IPS structure to a traditional common share structure. Each IPS has been exchanged for one new common share of and each old common share not forming part of an IPS was exchanged for approximately 0.44 of a new common share.

        In 2008, we approved a normal course issuer bid to purchase up to four million IPSs, representing approximately 8% of Atlantic Power's public float at the same time. As of December 31, 2009 and 2008, we acquired 481,600 and 558,620 IPSs at an average price of Cdn$8.42 and Cdn$8.78, respectively, under the terms of our existing normal course issuer bid. As of December 31, 2009, we have acquired a cumulative total of 1,040,220 IPSs at an average price of Cdn$8.61 since the inception of the issuer bid in July 2008. We paid the market price at the time of acquisition for any IPSs purchased through the facilities of the Toronto Stock Exchange, and all IPSs acquired under the bid have been cancelled. The issuer bid expired on July 24, 2009.

19. Commitments and contingencies

        Our Lake project is currently involved in a dispute with Progress Energy Florida over off-peak energy sales in 2010. All amounts billed for off-peak energy during 2010 by the Lake project have been paid in full by Progress. The Lake project has filed a claim against Progress in which we seek to confirm our contractual right to sell off-peak energy at the contractual price for such sales. Progress filed a counter-claim against the Lake project, seeking, among other things, the return of amounts paid for off-peak power sales during 2010 and a declaratory order clarifying Lake's rights and obligations under the PPA. The Lake project has stopped dispatching during off-peak periods pending the outcome of the dispute. However, we strongly believe that the court will confirm our contractual right to sell off-peak power using the contractual price that was used during 2010 and that we will be able to continue such off-peak power sales for the remainder of the term of the PPA. We have not recorded any reserves related to this dispute and expect that the outcome will not have a material adverse effect on our financial position or results of operations.

        From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending as of December 31, 2010 which are expected to have a material adverse impact on our financial position or results of operations.

Schedule I-133


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. Unaudited selected quarterly financial data

        Unaudited selected quarterly financial data is as follows:

 
  Quarter Ended  
 
  2010  
(In millions, except per share data)
  December 31,   September 30,   June 30,   March 31,  

Project revenue

  $ 46,092   $ 54,039   $ 47,904   $ 47,221  

Project income

    14,840     7,634     15,541     3,864  

Net income (loss) attributable to Atlantic Power Corporation

    1,304     (438 )   1,445     (6,063 )

Weighted average number of common shares outstanding—basic

    65,388     60,511     60,481     60,404  

Net income (loss) per weighted average common share—basic

  $ 0.02   $ (0.01 ) $ 0.02   $ (0.10 )

Weighted average number of common shares outstanding—diluted

    80,966     72,598     72,363     72,271  

Net income (loss) per weighted average common share—diluted*

  $ 0.02   $ (0.01 ) $ 0.02   $ (0.10 )

*
The calculation excludes potentially dilutive shares from convertible debentures because their impact would be anti-dilutive.


 
  Quarter Ended  
 
  2009  
(In millions, except per share data)
  December 31,   September 30,   June 30,   March 31,  

Project revenue

  $ 44,356   $ 44,857   $ 44,270   $ 46,034  

Project income

    17,976     4,444     11,461     14,534  

Net (loss) income

    (16,197 )   (15,803 )   (10,729 )   4,243  

Weighted average number of common shares outstanding—basic

    60,475     60,518     60,600     60,941  

Net (loss) income per weighted average common share—basic

  $ (0.27 ) $ (0.26 ) $ (0.18 ) $ 0.07  

Weighted average number of common shares outstanding—diluted

    66,797     65,812     65,978     66,088  

Net (loss) income per weighted average common share—diluted*

  $ (0.27 ) $ (0.26 ) $ (0.18 ) $ 0.07  

*
The calculation excludes potentially dilutive shares from convertible debentures and LTIP notional units because their impact would be anti-dilutive.

21. Subsequent events

        On February 28, 2011, we entered into a purchase and sale agreement with a third party for the purchase of our lessor interest in the Topsham project. Closing of the transaction is expected to occur in the second quarter of 2011.

22. United States and Canadian accounting policy differences

        In accordance with Canadian securities legislation, issuers that file reports with the Securities and Exchange Commission in the United States are allowed to file financial statements under United States GAAP to meet their continuous disclosure obligations in Canada. We have included a reconciliation

Schedule I-134


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. United States and Canadian accounting policy differences (Continued)


highlighting the material differences between our consolidated financial statements prepared in accordance with United States GAAP compared to our consolidated financial statements prepared in accordance with Canadian GAAP below.

Consolidated reconciliation of net income and shareholders' equity

        Net income (loss) and shareholders' equity reconciled to Canadian GAAP are as follows:

 
  2010   2009  

Net income (loss), based on United States GAAP

  $ (3,855 ) $ (38,486 )

Changes in fair value of power purchase agreement, net of tax(1)

    (12,704 )   15,899  

Projects accounted for under the cost method of accounting, net of tax(2)

    3,393     4,314  
           

Net income (loss), based on Canadian GAAP

  $ (13,166 ) $ (18,273 )
           

 

 
  December 31,  
 
  2010   2009  

Shareholders' equity, based on United States GAAP

  $ 433,376   $ 414,117  

Adjusted for cumulative effect of US/Canadian differences

    56,254     65,566  
           

Shareholders' equity, based on Canadian GAAP

  $ 489,630   $ 479,683  
           

(1)
The accounting standard under United States GAAP for derivative instruments provides an exemption for PPAs that contain both a capacity payment and an energy component which, if certain criteria are met, qualifies the PPA for the normal purchases and normal sales treatment. A similar exemption does not exist under Canadian GAAP and accordingly, a PPA with a capacity payment, a minimum or specified quantity of energy and delivery into a liquid market is subject to fair value accounting. Our PPA at the Chambers project meets the normal purchases and normal sales exemption under United States GAAP and is not subject to fair value accounting.

(2)
We follow a standard under United States GAAP that establishes a presumption of significant influence with a low threshold of ownership in investments in limited partnerships and requires accounting under the equity method. Our investments in the Selkirk and Gregory projects are accounted for under the cost method for Canadian GAAP because there is not a different threshold for ownership interest in limited partnerships and we do not exercise significant influence over the operating and financial policies of these investments.

Schedule I-135


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. United States and Canadian accounting policy differences (Continued)

Earnings per share

 
  2010   2009  

Earnings per share under Canadian GAAP

             
 

Loss from continuing operations per share—basic

  $ (0.21 ) $ (0.40 )
 

Income from discontinued operations per share—basic

        0.10  
           
 

Net loss per share—basic

  $ (0.21 ) $ (0.30 )
           
 

Loss from continuing operations per share—diluted

  $ (0.21 ) $ (0.40 )
 

Income from discontinued operations per share—diluted

        0.10  
           
 

Net loss per share—diluted

  $ (0.21 ) $ (0.30 )
           

Condensed consolidated balance sheet

 
  December 31,
2010
  December 31,
2009
 
 
  (Canadian GAAP)
  (Canadian GAAP)
 

Assets

             

Current assets

  $ 196,773   $ 149,340  

Equity investments in unconsolidated affiliates(1)

    98,766     61,037  

Other long-term assets

    847,974     827,175  
           
 

Total assets

  $ 1,143,513   $ 1,037,552  
           

Liabilities and Shareholders' Equity

             

Current liabilities

  $ 83,729   $ 77,471  

Other non-current liabilities(2)

    570,154     480,398  

Shareholders' equity:

             
 

Common shares

    625,495     541,304  
 

Accumulated other comprehensive income (loss)

    255     (859 )
 

Retained deficit

    (139,627 )   (60,762 )
 

Noncontrolling interest

    3,507      
           
 

Total shareholders' equity

    489,630     479,683  
           
 

Total liabilities and shareholders' equity

  $ 1,143,513   $ 1,037,552  
           

(1)
We follow a standard under United States GAAP that requires the equity method of accounting for our investments with 50% or less ownership interest in which we do not have a controlling interest. Under Canadian GAAP, our share of each of the assets, liabilities, revenues and expenses of our investments that are subject to joint control is proportionately consolidated.

(2)
Under United States GAAP, deferred financing costs related to long-term debt and convertible debentures is presented as a component of other long-term assets. Under Canadian GAAP, deferred financing costs related to long-term debt and convertible debentures is presented as a reduction of the carrying amount of long-term debt and convertible debentures. The balance of deferred financing costs included in other non-current liabilities for December 31, 2010 and 2009 was $16.7 million and $5.5 million, respectively.

Schedule I-136


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. United States and Canadian accounting policy differences (Continued)

Condensed consolidated statement of operations

 
  2010   2009  
 
  (Canadian GAAP)
  (Canadian GAAP)
 

Project Income

             
 

Project revenue

  $ 309,773   $ 288,281  
 

Project expenses

    233,575     224,572  
 

Project other expenses

    (65,739 )   (32,237 )
           

    10,459     31,472  

Administration and other expenses, net

    26,791     102,560  
           

Loss from operations before income taxes

    (16,332 )   (71,088 )

Income tax expense (benefit)

    (3,166 )   (46,551 )
           

Income from continuing operations

    (13,166 )   (24,537 )

Less: Net loss attributable to noncontrolling interest

    (103 )    

Loss from discontinued operations, net of tax

        6,264  
           

Net income (loss) attributable to Atlantic Power Corporation

  $ (13,063 ) $ (18,273 )
           

Condensed consolidated statement of cash flows

 
  2010   2009  
 
  (Canadian GAAP)
  (Canadian GAAP)
 

Cash provided by operating activities of continuing operations

  $ 98,542   $ 62,019  

Cash provided by operating activities of discontinued operations

        470  
           

    98,542     62,489  

Cash used in investing activities of continuing operations

   
(147,734

)
 
(71,773

)

Cash used in investing activities of discontinued operations

        (1,853 )
           

    (147,734 )   (73,626 )

Cash provided by (used in) financing activities of continuing operations

   
44,072
   
(6,226

)

Cash provided by financing activities of discontinued operations

        29,300  
           

    44,072     23,074  

Increase (decrease) in cash and cash equivalents

   
(5,120

)
 
11,937
 

Cash and cash equivalents, beginning of period

    54,503     42,566  
           

Cash and cash equivalents, end of period

  $ 49,383   $ 54,503  
           

Schedule I-137


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. United States and Canadian accounting policy differences (Continued)


NOTES TO RECONCILIATION TO CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

A) Joint venture investments

        We account for six entities under proportionate consolidation as of December 31, 2010:

Entity name
  Proportion
consolidated
 

Badger Creek Limited

    50.0 %

Orlando Cogen, LP

    50.0 %

Topsham Hydro Assets

    50.0 %

Onondaga Renewables, LLC

    50.0 %

Koma Kulshan Associates

    49.8 %

Chambers Cogen, LP

    40.0 %

        The following summarizes the balance sheets at December 31, 2010 and 2009, and operating results and distributions paid to for the years ended December 31, 2010 and 2009 for our proportionate share of the six joint venture entities:

 
  2010   2009  

Assets

             
 

Current assets

  $ 77,390   $ 48,070  
 

Non-Current assets

    265,239     341,630  
           

  $ 342,629   $ 389,700  

Liabilities

             
 

Current liabilities

  $ 22,367   $ 25,443  
 

Non-Current liabilities

    66,474     114,153  
           

  $ 88,841   $ 139,596  

Operating results

             
   

Revenue

  $ 114,517   $ 107,762  
   

Net loss

    (18,503 )   (194 )

Distributions paid from joint ventures

 
$

15,411
 
$

18,373
 


B) Capital management

        Our overall objectives in capital management are to optimize the cost of capital related to existing assets and growth opportunities, as well as maintaining a prudent capital structure whose risk characteristics do not jeopardize realization of long term value from our assets. Our capital structure consists of non-recourse project-level debt, a credit facility, convertible debentures and common stock.

        We currently pay a monthly dividend at an annual rate of Cdn$1.094 per common share. We have historically raised debt capital at the operating or project-level at lower interest rates than what would be required on corporate-level debt. These financings are structured as non-recourse to us and an adverse impact to debt at any single project has no influence on debt at other projects, and in virtually all cases the principal fully amortizes before the primary PPA expires.

Schedule I-138


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. United States and Canadian accounting policy differences (Continued)

        In some cases we may raise an additional tranche of non-recourse, fully-amortizing debt at a holding company that owns the project equity. The appropriate degree of total operating leverage is a function of assessing the potential volatility of projected cash flows to maintain a low probability that a temporary project operating issue could cause our equity in the project to be at risk before curing the problem. There are also lender safeguards in these financings such as debt service and major maintenance reserves that help mitigate impacts to our cash flow from temporary project operating issues.

        The credit facility is designed for several purposes: 1) to support letters of credit covering certain contingent performance risks at several projects, 2) to provide corporate liquidity in the case of significant unexpected temporary interruption or reductions to operating cash flows, and 3) to contribute to bridge financing for potential acquisitions. The credit facility has a total capacity of $100 million with two equal bank participants.

        Acquisition bridge facilities have also historically been placed at this senior corporate level with the revolving credit facility lenders. The capital structure is periodically reviewed by our management and Board of Directors to determine whether changes are required to meet the objectives outlined above. Other than the capital management decisions discussed, there were no other changes in our approach to capital management during the period. Neither we, nor any of our subsidiaries are subject to externally imposed capital requirements.


C) Financial risk management

        We have exposure to market risk, credit risk and liquidity risk from our use of financial instruments:

        Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and commodity prices, will affect our cash flows or the value of its holdings of financial instruments. The objective of market risk management is to minimize the impact that market risks have on our cash flows as described in the following paragraphs.

        We are exposed to changes in foreign currency exchange rates because it earns all of its income in U.S. dollars but has substantial obligations in Canadian dollars. We manage this risk through the use of foreign currency forward contracts and, where possible, establishing any new obligations in U.S. dollars instead of Canadian dollars.

        The impact of changes in interest rates do not have a significant impact on cash payments that are required on our debt instruments as approximately 86% of our debt, including non-recourse project-level debt and our share of debt at unconsolidated projects, bears interest at fixed rates.

        The debt obligations at our proportionately consolidated Chambers project bears interest at variable rates. Exposure to changes in interest rates related to this variable rate debt has been partially mitigated through the use of interest rate swaps. After considering the impact of interest rate swaps, a hypothetical change in the average interest rate of 100 basis points would change annual interest costs, including interest at proportionately consolidated projects, by approximately $0.9 million.

Schedule I-139


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. United States and Canadian accounting policy differences (Continued)

        Our current and future cash flows are impacted by changes in electricity, natural gas and coal prices. The combination of long-term energy sales and fuel purchase agreements are designed to generally mitigate the impacts to cash flows of changes in commodity prices by generally passing through changes in fuel prices to the buyer of the energy.

        Credit risk is the risk of financial loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. Our maximum exposure to credit risk is the carrying value of financial assets included in the consolidated balance sheet. Our exposure to credit losses from accounts receivable at its projects is mitigated by the fact that most projects sell power under long-term contracts with investment-grade utilities and other counterparties. We do not have a history of credit losses related to long-term contracts at the projects and no significant amounts are currently past due. Our risk of credit loss on other financial instruments is managed by conducting business with financial institutions that have strong credit ratings.

        Liquidity risk is the risk that we will not be able to meet its financial obligations as they become due. We believe that future cash flows from operating activities and access to additional liquidity through capital and bank markets will be adequate to meet its financial obligations.


D) Recently adopted Canadian accounting pronouncements

a) Goodwill and intangible assets

        Effective January 1, 2009, we adopted CICA Handbook Section 3064, "Goodwill and Intangible Assets", which replaces Section 3062, "Goodwill and Other Intangible Assets", and Section 3450, "Research and Development Costs" and establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Accounting Standard IAS 38, "Intangible Assets". The adoption of this standard did not impact our consolidated financial statements.

b) Business combinations

        On January 1, 2010, we adopted CICA Handbook Section 1582, "Business Combinations". This section establishes standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent consideration and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition related costs will be expensed as incurred, that restructuring charges will be expensed in periods after the acquisition date and that non-controlling interests should be measured at fair value at the date of acquisition. This standard is to be applied prospectively to business combinations with acquisition dates on or after January 1, 2010. This new standard was applied to the step-up acquisition of Rollcast and the acquisition of Cadillac.

Schedule I-140


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. United States and Canadian accounting policy differences (Continued)

c) Consolidated financial statements

        On January 1, 2010, we adopted CICA Handbook Section 1601, "Consolidated Financial Statements". The new standard replaces Section 1600, "Consolidated Financial Statements". This Section carries forward existing Canadian guidance for preparing consolidated financial statements other than guidance for non-controlling interests. The adoption of this standard did not have a material impact on our consolidated financial statements.

d) Non-controlling interests

        On January 1, 2010, we adopted CICA Handbook Section 1602, "Non-Controlling Interests". The new standard establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. The adoption of this standard did not have a material impact on our consolidated financial statements.


E) Recent Canadian accounting pronouncements announced but not yet effective

International Financial Reporting Standards (IFRS)

        The Canadian Accounting Standards Board has set January 1, 2011 as the date that IFRS will replace Canadian GAAP for publicly accountable enterprises, which includes Canadian reporting issuers. Financial reporting under IFRS differs from Canadian GAAP in a number of respects, some of which are significant. We report in U.S. GAAP and are not planning to adopt IFRS as we will no longer be required to provide a reconciliation to Canadian GAAP beyond December 31, 2010.

Schedule I-141


Table of Contents

VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
(in thousands)

 
  Balance at
Beginning of
Period
  Charged to
Costs and
Expenses
  Charged to
Other
Accounts
  Deductions   Balance at
End of
Period
 

Income tax valuation allowance, deducted from deferred tax assets:

                               

Year ended December 31, 2010

  $ 67,131   $ 12,289   $   $   $ 79,420  

Year ended December 31, 2009

    45,126     22,005             67,131  

Year ended December 31, 2008

    82,237     (37,111 )           45,126  

Schedule I-142


Table of Contents


Schedule II

Quarterly Report of Atlantic Power of Form 10-Q
for the Quarter Ended June 30, 2011


Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549



FORM 10-Q


ý

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

OR

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                   to                 

COMMISSION FILE NUMBER 001-34691

ATLANTIC POWER CORPORATION
(Exact name of registrant as specified in its charter)

British Columbia, Canada
(State or other jurisdiction of
incorporation or organization)
  55-0886410
(I.R.S. Employer
Identification No.)

200 Clarendon Street, Floor 25
Boston, MA

(Address of principal executive offices)

 

02116
(Zip code)

(617) 977-2400
(Registrant's telephone number, including area code)

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o   Accelerated filer o   Non-accelerated filer ý
(Do not check if a
smaller reporting company)
  Smaller reporting company o

        Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

        The number of shares outstanding of the registrant's Common Stock as of August 10, 2011 was 68,963,203.

Schedule II-1


Table of Contents


ATLANTIC POWER CORPORATION

FORM 10-Q

THREE AND SIX MONTHS ENDED JUNE 30, 2011

Index

 

General

   

 

PART I—FINANCIAL INFORMATION

  II-4

ITEM 1.

 

CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

  II-4

 

Consolidated Balance Sheets as of June 30, 2011 (unaudited) and December 31, 2010

  II-4

 

Consolidated Statements of Operations for the three and six month periods ended June 30, 2011 and June 30, 2010 (unaudited)

  II-5

 

Consolidated Statements of Cash Flows for the six month periods ended June 30, 2011 and June 30, 2010 (unaudited)

  II-6

 

Notes to Consolidated Financial Statements (unaudited)

  II-7

ITEM 2.

 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

  II-28

ITEM 3.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  II-48

ITEM 4.

 

CONTROLS AND PROCEDURES

  II-51

 

PART II—OTHER INFORMATION

  II-52

ITEM 1.

 

LEGAL PROCEEDINGS

  II-52

ITEM 1A.

 

RISK FACTORS

  II-52

ITEM 6.

 

EXHIBITS

  II-52

Schedule II-2


Table of Contents


GENERAL

        In this Quarterly Report on Form 10-Q, references to "Cdn$" and "Canadian dollars" are to the lawful currency of Canada and references to "$" and "US$" and "U.S. dollars" are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise indicated.

        Unless otherwise stated, or the context otherwise requires, references in this Quarterly Report on Form 10-Q to "we," "us," "our" and "Atlantic Power" refer to Atlantic Power Corporation, those entities owned or controlled by Atlantic Power Corporation and predecessors of Atlantic Power Corporation.

Schedule II-3


Table of Contents


PART I—FINANCIAL INFORMATION

ITEM 1.    CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

        


ATLANTIC POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands of U.S. dollars)

 
  June 30,
2011
  December 31,
2010
 
 
  (unaudited)
   
 

Assets

             

Current assets:

             
 

Cash and cash equivalents

  $ 46,551   $ 45,497  
 

Restricted cash

    21,034     15,744  
 

Accounts receivable

    20,028     19,362  
 

Note receivable—related party (Note 14)

    7,326     22,781  
 

Current portion of derivative instruments asset (Notes 8 and 9)

    9,297     8,865  
 

Prepayments, supplies, and other

    8,451     8,480  
 

Refundable income taxes

    1,611     1,593  
           
 

Total current assets

    114,298     122,322  

Property, plant, and equipment, net

   
308,051
   
271,830
 

Transmission system rights

    184,208     188,134  

Equity investments in unconsolidated affiliates (Note 4)

    276,962     294,805  

Other intangible assets, net

    77,425     88,462  

Goodwill

    12,453     12,453  

Derivative instruments asset (Notes 8 and 9)

    18,865     17,884  

Other assets

    16,718     17,122  
           
 

Total assets

  $ 1,008,980   $ 1,013,012  
           

Liabilities

             

Current Liabilities:

             
 

Accounts payable and accrued liabilities

  $ 16,333   $ 20,530  
 

Current portion of long-term debt (Note 6)

    21,962     21,587  
 

Current portion of derivative instruments liability (Notes 8 and 9)

    7,410     10,009  
 

Interest payable on convertible debentures (Note 7)

    1,948     3,078  
 

Dividends payable

    6,490     6,154  
 

Other current liabilities

    7     5  
           
 

Total current liabilities

    54,150     61,363  

Long-term debt (Note 6)

   
263,111
   
244,299
 

Convertible debentures (Note 7)

    209,703     220,616  

Derivative instruments liability (Notes 8 and 9)

    24,822     21,543  

Deferred income taxes

    23,594     29,439  

Other non-current liabilities

    2,121     2,376  

Commitments and contingencies (Note 15)

         
           
 

Total liabilities

    577,501     579,636  

Equity

             

Common shares, no par value, unlimited authorized shares; 68,639,654 and 67,118,154 issued and outstanding at June 30, 2011 and December 31, 2010 , respectively

    644,001     626,108  
 

Accumulated other comprehensive income (Note 9)

    24     255  
 

Retained deficit

    (215,782 )   (196,494 )
           
 

Total Atlantic Power Corporation shareholders' equity

    428,243     429,869  
           

Noncontrolling interest

    3,236     3,507  
           

Total equity

    431,479     433,376  
           

Total liabilities and equity

  $ 1,008,980   $ 1,013,012  
           

See accompanying notes to consolidated financial statements.

Schedule II-4


Table of Contents


ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands of U.S. dollars, except per share amounts)

(Unaudited)

 
  Three months ended
June 30,
  Six months ended
June 30,
 
 
  2011   2010   2011   2010  

Project revenue:

                         
 

Energy sales

  $ 17,865   $ 16,659   $ 36,367   $ 32,572  
 

Energy capacity revenue

    27,651     23,195     54,789     46,389  
 

Transmission services

    7,491     7,729     15,135     15,373  
 

Other

    251     321     632     791  
                   

    53,258     47,904     106,923     95,125  

Project expenses:

                         
 

Fuel

    14,316     15,771     31,384     31,928  
 

Operations and maintenance

    7,801     6,442     18,873     12,402  
 

Depreciation and amortization

    10,924     10,071     21,803     20,142  
                   

    33,041     32,284     72,060     64,472  

Project other income (expense):

                         
 

Change in fair value of derivative instruments
(Notes 8 and 9)

    (4,574 )   992     (1,013 )   (11,202 )
 

Equity in earnings of unconsolidated affiliates

    1,962     3,026     3,273     8,462  
 

Interest expense, net

    (4,543 )   (4,308 )   (9,190 )   (8,719 )
 

Other income (expense), net

    (31 )   211     (33 )   211  
                   

    (7,186 )   (79 )   (6,963 )   (11,248 )
                   

Project income

    13,031     15,541     27,900     19,405  

Administrative and other expenses (income):

                         
 

Administration

    4,671     3,843     8,725     7,943  
 

Interest, net

    3,510     2,518     7,478     5,312  
 

Foreign exchange (gain) loss (Note 9)

    (535 )   4,224     (1,193 )   2,432  
 

Other income, net

        (26 )       (26 )
                   

    7,646     10,559     15,010     15,661  
                   

Income from operations before income taxes

    5,385     4,982     12,890     3,744  

Income tax expense (benefit) (Note 10)

    (7,684 )   3,618     (6,161 )   8,491  
                   

Net income (loss)

    13,069     1,364     19,051     (4,747 )

Net loss attributable to noncontrolling interest

    (117 )   (81 )   (271 )   (129 )
                   

Net income (loss) attributable to Atlantic Power Corporation

  $ 13,186   $ 1,445   $ 19,322   $ (4,618 )
                   

Net income (loss) per share attributable to Atlantic Power Corporation shareholders: (Note 12)

                         
 

Basic

  $ 0.19   $ 0.02   $ 0.28   $ (0.08 )
 

Diluted

  $ 0.18   $ 0.02   $ 0.28   $ (0.08 )

Weighted average number of common shares
outstanding: (Note 12)

                         
 

Basic

    68,573     60,481     68,116     60,443  
 

Diluted

    82,939     60,890     82,973     60,443  

See accompanying notes to consolidated financial statements.

Schedule II-5


Table of Contents


ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands of U.S. dollars)

(Unaudited)

 
  Six months ended
June 30,
 
 
  2011   2010  

Cash flows from operating activities:

             

Net income (loss)

  $ 19,051   $ (4,747 )

Adjustments to reconcile to net cash provided by operating activities:

             
 

Depreciation and amortization

    21,803     20,142  
 

Long-term incentive plan expense

    1,639     2,149  
 

Gain on step-up valuation of Rollcast acquisition

        (211 )
 

Equity in earnings from unconsolidated affiliates

    (3,273 )   (8,462 )
 

Distributions from unconsolidated affiliates

    11,584     5,718  
 

Unrealized foreign exchange loss

    4,499     5,199  
 

Change in fair value of derivative instruments

    1,013     11,202  
 

Change in deferred income taxes

    (5,691 )   7,416  

Change in other operating balances

             
 

Accounts receivable

    (666 )   (953 )
 

Prepayments, refundable income taxes and other assets

    1,244     (481 )
 

Accounts payable and accrued liabilities

    (4,996 )   (1,970 )
 

Other liabilities

    (1,492 )   976  
           

Net cash provided by operating activities

    44,715     35,978  

Cash flows used in by investing activities:

             
 

Acquisitions and investments, net of cash acquired

        324  
 

Change in restricted cash

    (5,290 )   280  
 

Proceeds from sale of equity investments

    8,500      
 

Repayments from related party loan

    15,455      
 

Biomass development costs

    (587 )   (948 )
 

Purchase of property, plant and equipment

    (42,898 )   (1,520 )
           

Net cash used in investing activities

    (24,820 )   (1,864 )

Cash flows used in by financing activities:

             
 

Proceeds from project-level debt

    29,890      
 

Repayment of project-level debt

    (10,341 )   (9,141 )
 

Equity investment from noncontrolling interest

        200  
 

Proceeds from revolving credit facility borrowings

        20,000  
 

Dividends paid

    (38,390 )   (31,709 )
           

Net cash used in financing activities

    (18,841 )   (20,650 )
           

Net increase in cash and cash equivalents

    1,054     13,464  

Cash and cash equivalents at beginning of period

    45,497     49,850  
           

Cash and cash equivalents at end of period

  $ 46,551   $ 63,314  
           

Supplemental cash flow information

             
 

Interest paid

  $ 17,600   $ 11,437  
 

Income taxes paid (refunded), net

  $ (436 ) $ 1,045  

See accompanying notes to consolidated financial statements.

Schedule II-6


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of presentation and summary of significant accounting policies

Overview

        Atlantic Power Corporation owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Our power generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 megawatts (or "MW") in which our ownership interest is approximately 871 MW. Our current portfolio consists of interests in 12 operational power generation projects across nine states, one biomass project under construction in Georgia, and a 500 kilovolt 84-mile electric transmission line located in California. We also own a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development. Six of our projects are wholly-owned subsidiaries: Lake Cogen, Ltd., Pasco Cogen, Ltd., Auburndale Power Partners, L.P., Cadillac Renewable Energy, LLC, Piedmont Green Power, LLC and Atlantic Path 15, LLC.

        The interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission ("SEC") regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2010. Interim results are not necessarily indicative of results for the full year.

        In our opinion, the accompanying unaudited interim consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly our consolidated financial position as of June 30, 2011, the results of operations for the three and six-month periods ended June 30, 2011 and 2010, and our cash flows for the six-month periods ended June 30, 2011 and 2010.

Use of estimates:

        The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment and power purchase agreements ("PPAs"), the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the valuation of shares associated with our long-term incentive plan and the fair value of financial instruments and derivatives. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets if indications of impairment exist during the period. These estimates and assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying assumptions and estimates change, the recorded amounts could change by a material amount.

Schedule II-7


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. Basis of presentation and summary of significant accounting policies (Continued)

Reclassifications:

        Certain prior year amounts have been reclassified to conform to the current year presentation.

Recently issued accounting standards:

        In December 2010, the FASB issued changes to the disclosure of pro forma information for business combinations. These changes clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Also, the existing supplemental pro forma disclosures were expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We adopted these changes beginning January 1, 2011. Upon adoption, we determined these changes did not impact the consolidated financial statements.

        In December 2010, the FASB issued changes to the testing of goodwill for impairment. These changes require an entity to perform all steps in the test for a reporting unit whose carrying value is zero or negative if it is more likely than not (more than 50%) that a goodwill impairment exists based on qualitative factors, resulting in the elimination of an entity's ability to assert that such a reporting unit's goodwill is not impaired and additional testing is not necessary despite the existence of qualitative factors that indicate otherwise. We adopted these changes beginning January 1, 2011. Based on the most recent impairment review of our goodwill (2010 fourth quarter), we determined these changes did not impact the consolidated financial statements.

        In January 2010, the FASB issued changes to disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose, in the reconciliation of fair value measurements using significant unobservable inputs (Level 3), separate information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one net number) of these Level 3 financial instruments. We adopted these changes beginning January 1, 2011. We determined that these changes did not have an impact on the consolidated financial statements.

        In April 2010, the FASB issued changes to the classification of certain employee share-based payment awards. These changes clarify that there is not an indication of a condition that is other than market, performance, or service if an employee share-based payment award's exercise price is denominated in the currency of a market in which a substantial portion of the entity's equity securities trade and differs from the functional currency of the employer entity or payroll currency of the employee. An employee share-based payment award is required to be classified as a liability if the award does not contain a market, performance, or service condition. These changes were adopted beginning on January 1, 2011. We determined that these changes did not have an impact on the consolidated financial statements.

        In May 2011, the FASB issued changes to conform existing guidance regarding fair value measurement and disclosure between GAAP and International Financial Reporting Standards. These changes both clarify the FASB's intent about the application of existing fair value measurement and

Schedule II-8


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. Basis of presentation and summary of significant accounting policies (Continued)

disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity's shareholders' equity, and disclosure of quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a portfolio; application of premiums and discounts in a fair value measurement; and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to changes in unobservable inputs for those items categorized as Level 3, a reporting entity's use of a nonfinancial asset in a way that differs from the asset's highest and best use, and the categorization by level in the fair value hierarchy for items required to be measured at fair value for disclosure purposes only. These changes become effective on January 1, 2012. We are currently evaluating the potential impact of these changes on the consolidated financial statements.

        In June 2011, the FASB issued changes to the presentation of comprehensive income. These changes give an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements; the option to present components of other comprehensive income as part of the statement of changes in stockholders' equity was eliminated. The items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income were not changed. Additionally, no changes were made to the calculation and presentation of earnings per share. These changes become effective on January 1, 2012. We are currently evaluating these changes to determine which option will be chosen for the presentation of comprehensive income. Other than the change in presentation, we have determined these changes will not have an impact on the consolidated financial statements

2. Comprehensive income (loss)

        The following table summarizes the components of comprehensive income (loss) for the three and six-month periods ended June 30, 2011 and 2010:

 
  Three months ended
June 30,
  Six months ended
June 30,
 
 
  2011   2010   2011   2010  

Net income (loss)

  $ 13,069   $ 1,364   $ 19,051   $ (4,747 )

Unrealized gain (loss) on hedging activity

    (107 )   652     1,097     992  

less income tax (benefit) expense

    (43 )   261     439     397  
                   

Comprehensive income (loss)

  $ 13,005   $ 1,755   $ 19,709   $ (4,152 )
                   

Schedule II-9


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Acquisitions and divestitures

        

(a)
Capital Power Income L.P.

        On June 20, 2011, Atlantic Power, Capital Power Income L.P. ("CPILP"), CPI Income Services Ltd., the general partner of CPILP, and CPI Investments Inc., a unitholder of CPILP that is owned by EPCOR Utilities Inc. and Capital Power Corporation, entered into the Arrangement Agreement, which provides that Atlantic Power will acquire, directly or indirectly, all of the issued and outstanding CPILP units pursuant to the Plan of Arrangement under the Canada Business Corporations Act. Under the terms of the Plan of Arrangement, CPILP unitholders will be permitted to exchange each of their CPILP units for, at their election, Cdn$19.40 in cash or 1.3 Atlantic Power common shares. All cash elections will be subject to proration if total cash elections exceed approximately Cdn$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares.

        Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power, for approximately Cdn$121.0 million which equates to approximately Cdn$2.15 per unit of CPILP. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power and CPILP and certain of its subsidiaries will be terminated (or assigned) in consideration of a payment of Cdn$10.0 million. Atlantic Power or its subsidiaries will assume the management of CPILP and enter into a transitional services agreement with Capital Power for a term of 6 to 9 months following the completion of the Plan of Arrangement, which will facilitate the integration of CPILP into Atlantic Power.

        The Arrangement Agreement contains customary representations, warranties and covenants. Among these covenants, CPILP and CPI Income Services Ltd. have each agreed not to solicit alternative transactions, except that CPILP may respond to an alternative transaction proposal that constitutes, or would reasonably expect to lead to, a superior proposal that we would have the right to match. In addition, Atlantic Power or CPILP may be required to pay a Cdn$35.0 million fee if the Arrangement Agreement is terminated in certain unlikely circumstances.

        The completion of the Plan of Arrangement is subject to the receipt of all necessary court and regulatory approvals in Canada and the United States and certain other closing conditions. Atlantic Power and CPILP currently expect to complete the Plan of Arrangement in the fourth quarter of 2011, subject to receipt of required shareholder/unitholder, court and regulatory approvals and the satisfaction or waiver of the financing and other conditions to the Plan of Arrangement described in the Arrangement Agreement.

(b)
Topsham

        On February 28, 2011, we entered into a purchase and sale agreement with an affiliate of ArcLight Capital Partners, LLC ("ArcLight") for the purchase of our lessor interest in the project. The transaction closed on May 6, 2011 and we received proceeds of $8.5 million, resulting in no gain or loss on the sale.

Schedule II-10


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Equity method investments

        The following summarizes the operating results for the three and six months ended June 30, 2011 and 2010, respectively, for our equity earnings interest in our equity method investments:

 
  Three-months ended
June 30,
  Six-months ended
June 30,
 
 
  2011   2010   2011   2010  

Revenue

                         
 

Chambers

    13,009     13,329     26,278     28,746  
 

Badger Creek

    1,334     3,213     4,655     7,103  
 

Gregory

    7,633     7,687     14,814     16,553  
 

Orlando

    9,375     10,321     19,302     20,760  
 

Selkirk

    12,961     12,564     23,861     26,043  
 

Other

    3,132     1,930     4,952     3,170  
                   

    47,444     49,044     93,862     102,375  

Project expenses

                         
 

Chambers

    9,545     10,026     18,925     20,292  
 

Badger Creek

    1,414     2,755     4,398     6,225  
 

Gregory

    6,900     6,472     13,530     14,697  
 

Orlando

    9,605     9,869     19,068     19,915  
 

Selkirk

    12,631     11,921     25,289     24,749  
 

Other

    2,366     1,349     3,795     2,443  
                   

    42,461     42,392     85,005     88,321  

Project other income (expense)

                         
 

Chambers

    (663 )   (844 )   (1,090 )   (1,751 )
 

Badger Creek

    (7 )   193     (11 )   195  
 

Gregory

    (194 )   (891 )   (231 )   (685 )
 

Orlando

    (13 )   (33 )   (44 )   (66 )
 

Selkirk

    (929 )   (1,988 )   (2,566 )   (3,087 )
 

Other

    (1,215 )   (63 )   (1,642 )   (198 )
                   

    (3,021 )   (3,626 )   (5,584 )   (5,592 )

Project income (loss)

                         
 

Chambers

    2,801     2,459     6,263     6,703  
 

Badger Creek

    (87 )   651     246     1,073  
 

Gregory

    539     324     1,053     1,171  
 

Orlando

    (243 )   419     190     779  
 

Selkirk

    (599 )   (1,345 )   (3,994 )   (1,793 )
 

Other

    (449 )   518     (485 )   529  
                   

    1,962     3,026     3,273     8,462  

Schedule II-11


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Accumulated depreciation and amortization

        The following table presents accumulated depreciation of property, plant and equipment and the accumulated amortization of transmission system rights and other intangible assets as of June 30, 2011 and December 31, 2010:

 
  June 30,
2011
  December 31,
2010
 

Property, plant and equipment

  $ 98,248   $ 91,851  

Transmission system rights

    47,461     43,535  

Other intangible assets

    68,472     57,000  

6. Long-term debt

        Long-term debt represents project-level long-term debt of our consolidated subsidiaries and the unamortized balance of purchase accounting adjustments that were recorded in connection with the Path 15 acquisition in order to adjust the debt to its fair value on the acquisition date. Project-level debt is non-recourse to Atlantic Power and generally amortizes during the term of the respective revenue generating contracts of the projects.

 
  June 30,
2011
  December 31,
2010
 

Project debt, interest rates ranging from 5.1% to 9.0% maturing through 2028

  $ 274,131   $ 254,581  

Purchase accounting fair value adjustments

    10,942     11,305  

Less: current portion of long-term debt

    (21,962 )   (21,587 )
           

Long-term debt

  $ 263,111   $ 244,299  
           

        Project-level debt is secured by the respective project and its contracts with no other recourse to us. The loans have certain financial covenants that must be met. At June 30, 2011, all of our projects were in compliance with the covenants contained in the project-level debt. However, the holding company for our investment in the Chambers project, Epsilon Power Partners and the Delta-Person project had not achieved the levels of debt service coverage ratios required by the project-level debt arrangements as a condition to make distributions and were therefore restricted from making distributions to us.

        As of June 30, 2011 the inception to date balance on the Piedmont construction debt funded by the related bridge loan was $29.9 million. The Piedmont debt outstanding is funded by the bridge loan. The terms of the Piedmont project-level debt refinancing include an $82.0 million construction and term loan and a $51.0 million bridge loan for approximately 95.0% of the stimulus grant expected to be received from the U.S. Treasury 60 days after the start of commercial operations. The $51.0 million bridge loan will be repaid in 2012 and repayment of the expected $82.0 million term loan will commence in 2013.

Schedule II-12


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Convertible debentures

        The following table contains details related to outstanding convertible debentures:

 
  6.5% Debentures
due 2014
  6.25% Debentures
due 2017
  5.6% Debentures
due 2017
 

Balance at December 31, 2010 (Cdn$)

    55,801     83,124     80,500  

Principal amount converted to equity (Cdn$)

    (8,899 )   (8,267 )    
               

Balance at June 30, 2011 (Cdn$)

    46,902     74,857     80,500  

Balance at June 30, 2011 (US$)

    48,628     77,612     83,463  

Common shares issued on conversion during the six-months ended June 30, 2011

   
717,653
   
635,919
   
 

        Aggregate interest expense related to the convertible debentures was $3.0 million and $2.1 million for the three-month periods ended June 30, 2011 and 2010, respectively, and $6.4 million and $4.4 million for the six-month periods ended June 30, 2011 and 2010, respectively.

8. Fair value of financial instruments

        The following represents our financial assets and liabilities that were recognized at fair value as of June 30, 2011 and December 31, 2010. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

 
  June 30, 2011  
 
  Level 1   Level 2   Level 3   Total  

Assets:

                         
 

Cash and cash equivalents

  $ 46,551   $   $   $ 46,551  
 

Restricted cash

    21,034             21,034  
 

Derivative instruments asset

        28,162         28,162  
                   
 

Total

  $ 67,585   $ 28,162   $   $ 95,747  
                   

Liabilities:

                         
 

Derivative instruments liability

  $   $ 32,232   $   $ 32,232  
                   
 

Total

  $   $ 32,232   $   $ 32,232  
                   

 

 
  December 31, 2010  
 
  Level 1   Level 2   Level 3   Total  

Assets:

                         
 

Cash and cash equivalents

  $ 45,497   $   $   $ 45,497  
 

Restricted cash

    15,744             15,744  
 

Derivative instruments asset

        26,749         26,749  
                   
 

Total

  $ 61,241   $ 26,749   $   $ 87,990  
                   

Liabilities:

                         
 

Derivative instruments liability

  $   $ 31,552   $   $ 31,552  
                   
 

Total

  $   $ 31,552   $   $ 31,552  
                   

Schedule II-13


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Fair value of financial instruments (Continued)

        The fair value of our derivative instruments are based on price quotes from brokers in active markets who regularly facilitate those transactions and we believe such price quotes are executable. We adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating or the credit rating of our counterparties. As of June 30, 2011, the credit reserve resulted in a $0.6 million net increase in fair value, which is attributable to a $0.4 million pre-tax gain in other comprehensive income and a $0.4 million gain in change in fair value of derivative instruments, partially offset by a $0.2 million loss in foreign exchange. As of December 31, 2010, the credit reserve resulted in a $0.6 million net increase in fair value, which is attributable to a $0.2 million pre-tax gain in other comprehensive income and a $0.5 million gain in change in fair value of derivative instruments, partially offset by a $0.1 million loss in foreign exchange.

9. Accounting for derivative instruments and hedging activities

        We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:

 
  June 30, 2011  
 
  Derivative
Assets
  Derivative
Liabilities
 

Derivative instruments designated as cash flow hedges:

             
 

Interest rate swaps current

  $   $ 1,923  
 

Interest rate swaps long-term

        2,914  
           

Total derivative instruments designated as cash flow hedges

        4,837  
           

Derivative instruments not designated as cash flow hedges:

             
 

Interest rate swaps current

        2,317  
 

Interest rate swaps long-term

    2,580     2,910  
 

Foreign currency forward contracts current

    9,297      
 

Foreign currency forward contracts long-term

    16,285      
 

Natural gas swaps current

        3,170  
 

Natural gas swaps long-term

        18,998  
           

Total derivative instruments not designated as cash flow hedges

    28,162     27,395  
           

Total derivative instruments

  $ 28,162   $ 32,232  
           

Schedule II-14


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Accounting for derivative instruments and hedging activities (Continued)

 

 
  December 31, 2010  
 
  Derivative Assets   Derivative Liabilities  

Derivative instruments designated as cash flow hedges:

             
 

Interest rate swaps current

  $   $ 2,124  
 

Interest rate swaps long-term

        2,626  
           

Total derivative instruments designated as cash flow hedges

        4,750  
           

Derivative instruments not designated as cash flow hedges:

             
 

Interest rate swaps current

        1,286  
 

Interest rate swaps long-term

    3,299     2,000  
 

Foreign currency forward contracts current

    8,865      
 

Foreign currency forward contracts long-term

    14,585      
 

Natural gas swaps current

        6,599  
 

Natural gas swaps long-term

        16,917  
           

Total derivative instruments not designated as cash flow hedges

    26,749     26,802  
           

Total derivative instruments

  $ 26,749   $ 31,552  
           

Natural gas swaps

        The Lake project's operating margin is exposed to changes in natural gas spot market prices through the expiration of its PPA on July 31, 2013. The Auburndale project purchases natural gas under a fuel supply agreement which provides approximately 80% of the project's fuel requirements at fixed prices through June 30, 2012. The remaining 20% is purchased at spot market prices and therefore the project is exposed to changes in natural gas prices for that portion of its gas requirements through the termination of the fuel supply agreement and 100% of its natural gas requirements from the expiration of the fuel supply agreement in mid-2012 until the termination of its PPA at the end of 2013.

        In October 2010, we entered into natural gas swaps that are effective in 2014 and 2015. The natural gas swaps are related to our 50% share of expected fuel purchases at our Orlando project as its operating margin is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. In 2014, both the projected natural gas prices and the prices of these natural gas swaps are lower than the current price of natural gas being purchased under the project's gas contract. These financial swaps effectively fix the price of 1.2 million Mmbtu of natural gas at the Orlando project at a weighted average price of $5.76/Mmbtu and represent approximately 25% of our share of the expected natural gas purchases at the project during 2014 and 2015. These swap agreements were entered into by us and not at the project level. Orlando is accounted for under the equity method of accounting.

        Our strategy to mitigate the future exposure to changes in natural gas prices at Lake, Auburndale and Orlando consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheet at fair value.

Schedule II-15


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Accounting for derivative instruments and hedging activities (Continued)

        We have executed an interest rate swap at our consolidated Auburndale project to economically fix a portion of its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Auburndale debt agreement. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 3.12%. The notional amount of the swap matches the outstanding principal balance over the remaining life of Auburndale's debt. The interest rate swap was executed in November 2009 and expires on November 30, 2013.

        The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 6.02% from February 16, 2011 to February 15, 2015, 6.14% from February 16, 2015 to February 15, 2019, 6.26% from February 16, 2019 to February 15, 2023, and 6.38% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies for and is designated as a cash flow hedge, is effective through June 2025.

        We executed two interest rate swaps at our consolidated Piedmont project to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements are not designated as hedges and changes in their fair market value are recorded in the consolidated statements of operations. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.75% from March 31, 2011 to February 29, 2016. From February 2016 until the maturity of the debt in November 2017, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.47%. The swap continues at the fixed rate of 4.47% from the maturity of the debt in November 2017 until November 2030. The notional amounts of the interest rate swap agreements match the estimated outstanding principal balance of Piedmont's cash grant bridge loan and the construction loan facility which will convert to a term loan. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively.

        Unrealized gains (losses) on interest rate swaps designated as cash flow hedges have been recorded, net of tax, in shareholders' equity in other comprehensive income as a loss of $0.1 million and a gain of $0.4 million for the three-month periods ended June 30, 2011 and 2010, respectively, and a gain of $0.7 million and $0.6 million for the six-month periods ended June 30, 2011 and 2010 respectively. Settlements of these interest rate swaps of $0.6 million and $0.4 million were recorded in interest expense, net for the three-month periods ended June 30, 2011 and 2010, respectively, and $1.2 million and $0.7 million for the six-month periods ended June 30, 2011 and 2010, respectively.

        Unrealized gains and losses on natural gas swaps previously designated as cash flow hedges are recorded in other comprehensive income. In the period in which the unrealized gains and losses are settled, the cash settlement payments are recorded as fuel expense. A $5.1 million loss was recorded in other comprehensive loss for natural gas swap contracts accounted for as cash flow hedges prior to July 1, 2009 when hedge accounting for these natural gas swaps was discontinued prospectively. Amortization of the remaining loss in other comprehensive income of $(0.2) million and $0.4 million was recorded in change in fair value of derivative instruments for the three-month periods ended

Schedule II-16


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Accounting for derivative instruments and hedging activities (Continued)


June 30, 2011 and 2010, respectively, and $(0.3) million and $0.8 million for the six-month periods ended June 30, 2011 and 2010, respectively.

        Unrealized gains and losses on derivative instruments not designated as cash flow hedges are recorded in change in fair value of derivative instruments in the consolidated statements of operations.

        The following table summarizes realized (gains) and losses for derivative instruments not designated as cash flow hedges:

 
   
  Three months ended   Six months ended  
 
  Classification of (gain)
loss recognized in income
  June 30,
2011
  June 30,
2010
  June 30,
2011
  June 30,
2010
 

Natural gas swaps

  Fuel   $ 2,055   $ 2,621   $ 4,531   $ 4,439  

Foreign currency forwards

  Foreign exchange (gain) loss     (3,155 )   (1,599 )   (5,692 )   (2,767 )

Interest rate swaps

  Interest, net     955     474     1,931     949  

        Unrealized gains and losses associated with changes in the fair value of derivative instruments not designated as cash flow hedges and ineffectiveness of derivatives designated as cash flow hedges are reflected in current period earnings. The following table summarizes the pre-tax gains and (losses) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:

 
  Three months ended
June 30,
  Six months ended
June 30,
 
 
  2011   2010   2011   2010  

Change in fair value of derivative instruments:

                         
 

Interest rate swaps

  $ (3,337 ) $ (120 ) $ (2,659 ) $ (166 )
 

Natural gas swaps

    (1,237 )   1,112     1,646     (11,036 )
                   

  $ (4,574 ) $ 992   $ (1,013 ) $ (11,202 )
                   

        We entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the normal purchases and normal sales exception as of June 30, 2011:

 
  Units   June 30,
2011
 

Interest rate swaps

  Interest (US$)   $ 55,147  

Currency forwards

  Dollars (Cdn$)   $ 181,900  

Natural gas swaps

  Natural Gas (Mmbtu)     13,660  

Schedule II-17


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Accounting for derivative instruments and hedging activities (Continued)

        We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as we generate cash flow in U.S. dollars but pay dividends to shareholders and interest on convertible debentures predominantly in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on the long-term sustainability of dividends to shareholders. We have executed this strategy by entering into forward contracts to purchase Canadian dollars at a fixed rate to hedge approximately 86% of our expected dividend and convertible debenture interest payments through 2013. Changes in the fair value of the forward contracts partially offset foreign exchange gain or losses on the U.S. dollar equivalent of our Canadian dollar obligations. The forward contracts consist of (1) monthly purchases through the end of 2013 of Cdn$6.0 million at an exchange rate of Cdn$1.134 per U.S. dollar and (2) purchases in both April and October 2011 of Cdn$1.9 million at an exchange rate of Cdn$1.1075 per U.S. dollar.

        It is our intention to periodically consider extending the length of these forward contracts.

        The foreign exchange forward contracts are recorded at fair value based on quoted market prices and our estimation of the counterparty's credit risk. The fair value of our forward foreign currency contracts is $25.6 million and $23.4 million at June 30, 2011 and December 31, 2010, respectively. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations.

        The following table contains the components of recorded foreign exchange (gain) loss for the three and six-month periods ended June 30, 2011 and 2010:

 
  Three months ended
June 30,
  Six months ended
June 30,
 
 
  2011   2010   2011   2010  

Unrealized foreign exchange (gain) loss:

                         
 

Convertible debentures

  $ 1,317   $ (6,486 ) $ 6,632   $ (2,505 )
 

Forward contracts and other

    1,303     12,309     (2,133 )   7,704  
                   

    2,620     5,823     4,499     5,199  

Realized foreign exchange gains on forward contract settlements

    (3,155 )   (1,599 )   (5,692 )   (2,767 )
                   

  $ (535 ) $ 4,224   $ (1,193 ) $ 2,432  
                   

        The following table illustrates the impact on our financial instruments of a 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar as of June 30, 2011:

Convertible debentures, at carrying value

  $ 20,970  

Foreign currency forward contracts

  $ (20,548 )

Schedule II-18


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Accounting for derivative instruments and hedging activities (Continued)

        The following table summarizes the changes in the accumulated other comprehensive income (loss) ("OCI") balance attributable to derivative financial instruments designated as a hedge, net of tax:

For the three month period ended June 30, 2011
  Interest Rate
Swaps
  Natural Gas
Swaps
  Total  

Accumulated OCI balance at March 31, 2011

  $ (66 ) $ 593   $ 527  

Change in fair value of cash flow hedges

    (64 )       (64 )

Realized from OCI during the period

    (349 )   (90 )   (439 )
               

Accumulated OCI balance at June 30, 2011

  $ (479 ) $ 503   $ 24  
               

 

For the three month period ended June 30, 2010
  Interest Rate
Swaps
  Natural Gas
Swaps
  Total  

Accumulated OCI balance at March 31, 2010

  $ (554 ) $ (73 ) $ (627 )

Change in fair value of cash flow hedges

    391         391  

Realized from OCI during the period

    (211 )   253     42  
               

Accumulated OCI balance at June 30, 2010

  $ (374 ) $ 180   $ (194 )
               

 

For the six month period ended June 30, 2011
  Interest Rate
Swaps
  Natural Gas
Swaps
  Total  

Accumulated OCI balance at December 31, 2010

  $ (427 ) $ 682   $ 255  

Change in fair value of cash flow hedges

    658         658  

Realized from OCI during the period

    (710 )   (179 )   (889 )
               

Accumulated OCI balance at June 30, 2011

  $ (479 ) $ 503   $ 24  
               

 

For the six month period ended June 30, 2010
  Interest Rate
Swaps
  Natural Gas
Swaps
  Total  

Accumulated OCI balance at December 31, 2009

  $ (538 ) $ (321 ) $ (859 )

Change in fair value of cash flow hedges

    595         595  

Realized from OCI during the period

    (431 )   501     70  
               

Accumulated OCI balance at June 30, 2010

  $ (374 ) $ 180   $ (194 )
               

10. Income taxes

        The difference between the actual tax benefit of $7.7 million and $6.2 million for the three and six months ended June 30, 2011, respectively, and the expected income tax expense, based on the Canadian enacted statutory rate of 26.5%, of $1.4 million and $3.4 million, respectively is primarily due

Schedule II-19


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Income taxes (Continued)


to the change in basis of the Idaho Wind assets due to the receipt of the proceeds of the stimulus grant as well as a decrease in the valuation allowance and various other permanent differences.

 
  Three months ended
June 30,
  Six months ended
June 30,
 
 
  2011   2010   2011   2010  

Current income tax expense (benefit)

  $ 18   $ 1,038   $ (470 ) $ 1,075  

Deferred tax expense (benefit)

    (7,702 )   2,580     (5,691 )   7,416  
                   

Total income tax expense (benefit)

  $ (7,684 ) $ 3,618   $ (6,161 ) $ 8,491  
                   

        As of June 30, 2011, we have recorded a valuation allowance of $78.4 million. This amount is comprised primarily of provisions against available Canadian and U.S net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

11. Long-Term Incentive Plan

        The following table summarizes the changes in outstanding LTIP notional units during the six months ended June 30, 2011:

 
  Units   Grant Date
Weighted-Average
Price per Unit
 

Outstanding at December 31, 2010

    600,981   $ 10.28  

Granted

    153,094   $ 14.18  

Forfeited

    (101,559 ) $ 11.61  

Additional shares from dividends

    20,302   $ 10.95  

Vested and redeemed

    (263,523 ) $ 9.40  
           

Outstanding at June 30, 2011

    409,295   $ 11.85  
           

        Certain awards have a market condition based on our total shareholder return during the performance period compared to a group of peer companies. Compensation expense for notional units granted in 2011 is recorded net of estimated forfeitures. See further details as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010.

Schedule II-20


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Long-Term Incentive Plan (Continued)

        The calculation of simulated total shareholder return under the Monte Carlo model for the remaining time in the performance period for awards with market conditions included the following assumptions as of June 30, 2011:

Weighted average risk free rate of return

  0.39% – 0.72%

Dividend yield

  7.5%

Expected volatility—Company

  20.5% – 25.9%

Expected volatility—peer companies

  15.2% – 92.7%

Weighted average remaining measurement period

  1.26 years

12. Basic and diluted earnings (loss) per share

        Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be issued if all of the convertible debentures were converted into shares at January 1, 2011. Dilutive potential shares also include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP.

        Because we reported a loss for the six months ended June 30, 2010, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is

Schedule II-21


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Basic and diluted earnings (loss) per share (Continued)


anti-dilutive. The following table sets forth the diluted net income (loss) and potentially dilutive shares utilized in the per share calculation for the three and six month periods ended June 30, 2011 and 2010:

 
  Three months ended
June 30,
  Six months ended
June 30,
 
 
  2011   2010   2011   2010  

Numerator:

                         

Net income (loss) attributable to Atlantic Power Corporation

  $ 13,186   $ 1,445   $ 19,322   $ (4,618 )

Add: interest expense for potentially dilutive convertible debentures, net(1)

    1,931         3,985      
                   

Diluted net income (loss) attributable to Atlantic Power Corporation

    15,117     1,445     23,307     (4,618 )
                   

(1)
The above adjustment for net interest on the potential common shares that would be issued on the conversion of the convertible debentures has been excluded as the impact would be anti-dilutive for the three and six months ended June 30, 2010.

 
  Three months ended
June 30,
  Six months ended
June 30,
 
 
  2011   2010   2011   2010  

Denominator:

                         

Weighted average basic shares outstanding

    68,573     60,481     68,116     60,443  

Dilutive potential shares:

                         
 

Convertible debentures

    14,055     11,473     14,430     11,473  
 

LTIP notional units

    311     409     427     402  
                   

Potentially dilutive shares

    82,939     72,363     82,973     72,318  
                   

Diluted EPS

  $ 0.18   $ 0.02   $ 0.28   $ (0.08 )
                   

        Potentially dilutive shares from convertible debentures for the three and six-month periods ended June 30, 2010 have been excluded from fully diluted because their impact would be anti-dilutive.

13. Segment and related information

        We have six reportable segments: Path 15, Auburndale, Lake, Pasco, Chambers and Other Project Assets.

        We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are

Schedule II-22


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Segment and related information (Continued)


required to be recorded at fair value. A reconciliation of project income to Project Adjusted EBITDA is included in the table below.

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other
Project
Assets
  Un-allocated
Corporate
  Consolidated  

Three month period ended June 30, 2011:

                                                 

Operating revenues

  $ 7,491   $ 20,434   $ 16,844   $ 3,382   $ 0   $ 5,107   $ 0   $ 53,258  

Segment assets

    207,838     98,152     105,782     37,564     147,572     329,052     83,020     1,008,980  

Project Adjusted EBITDA

  $ 7,186   $ 11,606   $ 8,424   $ 1,469   $ 4,307   $ 9,862   $ 0   $ 42,854  

Change in fair value of derivative instruments

        1,145     (297 )       200     3,778         4,826  

Depreciation and amortization

    2,005     4,959     2,290     757     844     6,806         17,661  

Interest, net

    2,943     282     (2 )       1,413     2,452         7,088  

Other project (income) expense

                    201     47         248  
                                   

Project income

    2,238     5,220     6,433     712     1,649     (3,221 )       13,031  

Interest, net

                            3,510     3,510  

Administration

                            4,671     4,671  

Foreign exchange gain

                            (535 )   (535 )

Income (loss) from operations before income taxes

    2,238     5,220     6,433     712     1,649     (3,221 )   (7,646 )   5,385  

Income tax expense (benefit)

                            (7,684 )   (7,684 )
                                   

Net income (loss)

    2,238     5,220     6,433     712     1,649     (3,221 )   38     13,069  
                                   

 

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other Project Assets   Un-allocated Corporate   Consolidated  

Three month period ended June 30, 2010:

                                                 

Operating revenues

  $ 7,729   $ 19,570   $ 17,842   $ 2,763   $ 0   $ 0   $ 0   $ 47,904  

Segment assets

    213,904     121,303     115,822     40,620     136,351     131,560     102,964     862,524  

Project Adjusted EBITDA

  $ 7,062   $ 10,431   $ 7,299   $ 1,002   $ 4,141   $ 8,591   $ 0   $ 38,526  

Change in fair value of derivative instruments

        597     (1,709 )       (207 )   1,529         210  

Depreciation and amortization

    2,095     4,950     2,267     746     839     5,699         16,596  

Interest, net

    3,096     415     (4 )       1,651     939         6,097  

Other project (income) expense

                    204     (122 )       82  
                                   

Project income

    1,871     4,469     6,745     256     1,654     546         15,541  

Interest, net

                            2,518     2,518  

Administration

                            3,843     3,843  

Foreign exchange loss

                            4,224     4,224  

Other expense, net

                            (26 )   (26 )

Income (loss) from operations before income taxes

    1,871     4,469     6,745     256     1,654     546     (10,559 )   4,982  

Income tax expense (benefit)

    990                         2,628     3,618  
                                   

Net income (loss)

    881     4,469     6,745     256     1,654     546     (13,187 )   1,364  
                                   

Schedule II-23


Table of Contents


ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Segment and related information (Continued)

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other Project Assets   Un-allocated Corporate   Consolidated  

Six month period ended June 30, 2011:

                                                 

Operating revenues

  $ 15,135   $ 42,216   $ 33,968   $ 5,902   $ 0   $ 9,702   $ 0   $ 106,923  

Segment assets

    207,838     98,152     105,782     37,564     147,572     329,052     83,020     1,008,980  

Project Adjusted EBITDA

  $ 13,756   $ 21,919   $ 16,914   $ 392   $ 9,031   $ 16,835   $ 0   $ 78,847  

Change in fair value of derivative instruments

        184     (1,862 )       (552 )   4,272         2,042  

Depreciation and amortization

    3,979     9,918     4,580     1,514     1,679     13,428         35,098  

Interest, net

    5,934     595     (5 )       2,801     4,003         13,328  

Other project (income) expense

                    400     79         479  
                                   

Project income

    3,843     11,222     14,201     (1,122 )   4,703     (4,947 )       27,900  

Interest, net

                            7,478     7,478  

Administration

                            8,725     8,725  

Foreign exchange gain

                            (1,193 )   (1,193 )

Income (loss) from operations before income taxes

    3,843     11,222     14,201     (1,122 )   4,703     (4,947 )   (15,010 )   12,890  

Income tax expense (benefit)

                            (6,161 )   (6,161 )
                                   

Net income (loss)

    3,843     11,222     14,201     (1,122 )   4,703     (4,947 )   (8,849 )   19,051  
                                   

 

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other Project Assets   Un-allocated Corporate   Consolidated  

Six month period ended June 30, 2010:

                                                 

Operating revenues

  $ 15,373   $ 40,037   $ 34,083   $ 5,632   $ 0   $ 0   $ 0   $ 95,125  

Segment assets

    213,904     121,303     115,822     40,620     136,351     131,560     102,964     862,524  

                                  3,535              

Project Adjusted EBITDA

  $ 14,115   $ 19,802   $ 14,612   $ 2,417   $ 10,129   $ 16,200   $ 0   $ 77,275  

Change in fair value of derivative instruments

        4,809     6,226         (380 )   2,074         12,729  

Depreciation and amortization

    4,194     9,898     4,536     1,492     1,676     11,186         32,982  

Interest, net

    6,242     886     (6 )       3,327     1,429         11,878  

Other project (income) expense

                    403     (122 )       281  
                                   

Project income

    3,679     4,209     3,856     925     5,103     1,633         19,405  

Interest, net

                            5,312     5,312  

Administration

                            7,943     7,943  

Foreign exchange gain

                            2,432     2,432  

Other expense, net

                            (26 )   (26 )

Income (loss) from operations before income taxes

    3,679     4,209     3,856     925     5,103     1,633     (15,661 )   3,744  

Income tax expense (benefit)

    1,739                         6,752     8,491  
                                   

Net income (loss)

    1,940     4,209     3,856     925     5,103     1,633     (22,413 )   (4,747 )
                                   

        Progress Energy Florida and the California Independent System Operator ("CAISO") provide for 69% and 14%, respectively, of total consolidated revenues for the three-months ended June 30, 2011 and 77% and 16% for the three-months ended June 30, 2010. Progress Energy Florida and CAISO provide for 70% and 14%, respectively, of total consolidated revenues for the six-months ended June 30, 2011 and 77% and 16% for the six-months ended June 30, 2010. Progress Energy Florida purchases electricity from Auburndale and Lake, and the CAISO makes payments to Path 15.

Schedule II-24


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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. Related party transactions

        On February 28, 2011, we entered into a purchase and sale agreement with an affiliate of ArcLight for the purchase of our lessor interest in the Topsham project. The transaction closed on May 6, 2011 and we received proceeds of $8.5 million, resulting in no gain or loss on the sale.

        During 2010, we made short-term loans totaling $22.8 million to Idaho Wind to provide temporary funding for construction of the project until a portion of the project-level construction financing is completed. Member loans will be paid down with a combination of excess proceeds from the federal stimulus grant after repaying the cash grant facility, funds from a third closing for additional debt and project cash flow. The federal stimulus grant was approved in June of 2011 and the funds have been received. The third closing from additional debt is expected by the end of the year. The outstanding loans bear interest at a prime rate plus 10% (13.25% as June 30, 2011). During the six-months ended June 30, 2011, we received $1.2 million in interest payments related to the member loans. As of August 10, 2011, $15.5 million of the loans have been repaid.

        Prior to December 31, 2009, Atlantic Power was managed by Atlantic Power Management, LLC (the "Manager"), which was owned by two private equity funds managed by ArcLight. On December 31, 2009, we terminated our management agreements with the Manager and have agreed to pay the ArcLight funds an aggregate of $15.0 million, to be satisfied by a payment of $6.0 million that was made at the termination date, and additional payments of $5.0 million, $3.0 million and $1.0 million on the respective first, second and third anniversaries of the termination date. The remaining liability associated with the termination fee is recorded at its estimated fair value of $3.8 million at June 30, 2011. The contract termination liability is being accreted to the final amounts due over the term of these payments.

15. Commitments and contingencies

        Our Lake project is currently involved in a dispute with Progress Energy Florida over off-peak energy sales in 2010. All amounts billed for off-peak energy during 2010 by the Lake project have been paid in full by Progress. The Lake project has filed a claim against Progress in which we seek to confirm our contractual right to sell off-peak energy at the contractual price for such sales. Progress filed a counter-claim against the Lake project, seeking, among other things, the return of amounts paid for off-peak power sales during 2010 and a declaratory order clarifying Lake's rights and obligations under the PPA. The Lake project has stopped dispatching during off-peak periods pending the outcome of the dispute. However, we strongly believe that the court will confirm our contractual right to sell off-peak power using the contractual price that was used during 2010 and that we will be able to continue such off-peak power sales for the remainder of the term of the PPA. We have not recorded any reserves related to this dispute and expect that the outcome will not have a material adverse effect on our financial position or results of operations.

        From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending as of June 30, 2011 which are expected to have a material adverse impact on our financial position or results of operations.

Schedule II-25


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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Subsequent event

        On July 27, 2011, August 3, 2011 and August 5, 2011 we executed a series of financial transactions with an exercise date of January 18, 2012, to economically hedge a portion of the foreign currency exchange risk associated with the closing of the CPILP transaction.

        The July 27, 2011 transactions include a forward purchase of $32.0 million at $0.9460 per Cdn$1.00, a call option to purchase $84.7 million at $0.94565 per Cdn$1.00 and a put option to sell $116.7 million at $0.90 per Cdn$1.00. The August 3, 2011 transactions include a forward purchase of $76.0 million at $0.9665 per Cdn$1.00, a call option to purchase $14.5 million at $0.9665 per Cdn$1.00 and a put option to sell $90.5 million at $0.90 per Cdn$1.00. The August 5, 2011 transactions include a forward purchase of $81.2 million at $0.9872 per Cdn$1.00, a call option to purchase $9.3 million at $0.9872 per Cdn$1.00 and a put option to sell $90.5 million at $0.90 per Cdn$1.00.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

        Certain statements in this Quarterly Report on Form 10-Q constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements generally can be identified by the use of forward-looking terminology such as "outlook," "objective," "may," "will," "expect," "intend," "estimate," "anticipate," "believe," "should," "plans," "continue," or similar expressions suggesting future outcomes or events. Examples of such statements in this Quarterly Report on Form 10-Q include, but are not limited to, statements with respect to the following:

        Such forward-looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this Quarterly Report on Form 10-Q. Such forward-looking statements are based on a number of assumptions which may prove to be incorrect, including, but not limited to the assumption that the projects will operate and perform in accordance with our expectations. Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements, including, but not limited to, the factors discussed under "Risk Factors" included in the filings we make from time to time with the SEC. Our business is both competitive and subject to various risks.

        These risks include, without limitation:

Schedule II-27


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        Other factors, such as general economic conditions, including exchange rate fluctuations, also may have an effect on the results of our operations. Many of these risks and uncertainties can affect our actual results and could cause our actual results to differ materially from those expressed or implied in any forward-looking statement made by us or on our behalf.

        Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward-looking information include third party projections of regional fuel and electric capacity and energy prices or cash flows that are based on assumptions about future economic conditions and courses of action. Although the forward-looking statements contained in this Quarterly Report on Form 10-Q are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material. Certain statements included in this Quarterly Report on Form 10-Q may be considered "financial outlook" for the purposes of applicable securities laws, and such financial outlook may not be appropriate for purposes other than this Quarterly Report on Form 10-Q.

        These forward-looking statements are made as of the date of this Form 10-Q, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.

ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion of the financial condition and results of operations of Atlantic Power Corporation should be read in conjunction with the interim consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q.


OVERVIEW

        Atlantic Power Corporation owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Our power generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 MW in which our ownership interest is approximately 871 MW. Our current portfolio consists of interests in 12 operational power generation projects across nine states, one biomass project under construction in Georgia, and a 500 kilovolt 84-mile electric transmission line located in California. We also own a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development. We sell the capacity and energy from our power generation projects under power purchase agreements (or "PPAs") with a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2011 to 2037, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). We also sell steam from a number of our projects under steam sales agreements to industrial purchasers. The transmission system rights (or "TSRs") we own in our power transmission project entitle us to payments indirectly from the utilities that make use of the transmission line.

        Our power generation projects generally operate pursuant to long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel costs to our customers. In cases where there is not a pass-through of fuel costs, we use a financial hedging strategy designed to mitigate a portion of the market price risk of fuel purchases.

        We partner with recognized leaders in the independent power industry to operate and maintain our projects, including Caithness Energy, LLC, Power Plant Management Services, Delta Power

Schedule II-28


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Services and the Western Area Power Administration. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

        We completed our initial public offering on the Toronto Stock Exchange (TSX: ATP) in November 2004. Our shares began trading on the NYSE under the symbol "AT" on July 23, 2010.

        As of August 10, 2011, we had 68,963,203 common shares, Cdn$45.2 million ($47.5 million) principal amount of 6.50% convertible secured debentures due October 31, 2014 (the "2006 Debentures"), Cdn$72.4million ($76.1 million) principal amount of 6.25% convertible debentures due March 15, 2017 (the "2009 Debentures"), and Cdn$80.5 million ($84.6 million) principal amount of 5.60% convertible debentures due June 30, 2017 (the "2010 Debentures" and together with the 2006 and 2009 Debentures, the "Debentures") outstanding. The 2006 Debentures, 2009 Debentures and 2010 Debentures are convertible at any time, at the option of the holder, into 80.645, 76.923 and 55.249, respectively, common shares per Cdn$1,000 principal amount of Debentures, representing a conversion price of Cdn$12.40, Cdn$13.00 and Cdn$18.10, respectively, per common share. Holders of common shares currently receive a monthly dividend at a current annual rate of Cdn$1.094 per common share.


RECENT DEVELOPMENTS

        On June 20, 2011, Atlantic Power, Capital Power Income L.P. ("CPILP"), CPI Income Services Ltd., the general partner of CPILP, and CPI Investments Inc., a unitholder of CPILP that is owned by EPCOR Utilities Inc. and Capital Power Corporation, entered into the Arrangement Agreement, which provides that Atlantic Power will acquire, directly or indirectly, all of the issued and outstanding CPILP units pursuant to the Plan of Arrangement under the Canada Business Corporations Act. Under the terms of the Plan of Arrangement, CPILP unitholders will be permitted to exchange each of their CPILP units for, at their election, Cdn$19.40 in cash or 1.3 Atlantic Power common shares. All cash elections will be subject to proration if total cash elections exceed approximately Cdn$506.5 million and all share elections will be subject to proration if total share elections exceed approximately 31.5 million Atlantic Power common shares.

        Pursuant to the Plan of Arrangement, CPILP will sell its Roxboro and Southport facilities located in North Carolina to an affiliate of Capital Power, for approximately Cdn$121.0 million which equates to approximately Cdn$2.15 per unit of CPILP. Additionally, in connection with the Plan of Arrangement, the management agreements between certain subsidiaries of Capital Power and CPILP and certain of its subsidiaries will be terminated (or assigned) in consideration of a payment of Cdn$10.0 million. Atlantic Power or its subsidiaries will assume the management of CPILP and enter into a transitional services agreement with Capital Power for a term of up to 6 to 9 months following the completion of the Plan of Arrangement, which will facilitate the integration of CPILP into Atlantic Power.

        The Arrangement Agreement contains customary representations, warranties and covenants. Among these covenants, CPILP and CPI Income Services Ltd. have each agreed not to solicit alternative transactions, except that CPILP may respond to an alternative transaction proposal that constitutes, or would reasonably expect to lead to, a superior proposal, that we have a right to match. In addition, Atlantic Power or CPILP may be required to pay a Cdn$35.0 million fee if the Arrangement Agreement is terminated in certain unlikely circumstances.

        The completion of the Plan of Arrangement is subject to the receipt of all necessary court and regulatory approvals in Canada and the United States and certain other closing conditions. Atlantic Power and CPILP currently expect to complete the Plan of Arrangement in the fourth quarter of 2011, subject to receipt of required shareholder/unitholder, court and regulatory approvals and other conditions to the Plan of Arrangement described in the Arrangement Agreement.

        On May 6, 2011 we closed the sale of our 50.0% lessor interest in the Topsham project for $8.5 million, resulting in no gain or loss on the sale.

Schedule II-29


Table of Contents


OUR POWER PROJECTS

        The following table outlines our portfolio of power generating and transmission assets in operation and under construction as of August10, 2011, including our interest in each facility. Management believes the portfolio is well diversified in terms of electricity and steam buyers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region.


 
Project Name
  Location
(State)

  Type
  Total
MW

  Economic
Interest(1)

  Net
MW(2)

  Electricity
Purchaser

  Power
Contract
Expiry

  Customer
S&P Credit
Rating


 
Auburndale   Florida   Natural Gas     155     100.00 %   155   Progress Energy Florida     2013   BBB+

 
Lake   Florida   Natural Gas     121     100.00 %   121   Progress Energy Florida     2013   BBB+

 
Pasco   Florida   Natural Gas     121     100.00 %   121   Tampa Electric Co.     2018   BBB+

 
Chambers   New Jersey   Coal     262     40.00 %   89   ACE(3)     2024   BBB+
                         
 
                          16   DuPont     2024   A

 
Path 15   California   Transmission     N/A     100.00 %   N/A   California Utilities via CAISO(4)     N/A (5) BBB+ to A(6)

 
Orlando   Florida   Natural Gas     129     50.00 %   46   Progress Energy Florida     2023   BBB+
                         
 
                          19   Reedy Creek Improvement District     2013 (7) A1(8)

 
Selkirk   New York   Natural Gas     345     17.70% (9)   15   Merchant     N/A   N/R
                         
 
                          49   Consolidated Edison     2014   A-

 
Gregory   Texas   Natural Gas     400     17.10 %   59   Fortis Energy Marketing and Trading     2013   AA
                         
 
                          9   Sherwin Alumina     2020   NR

 
Badger Creek   California   Natural Gas     46     50.00 %   23   Pacific Gas & Electric     2012 (10) BBB+

 
Koma Kulshan   Washington   Hydro     13     49.80 %   6   Puget Sound Energy     2037   BBB

 
Delta-Person   New Mexico   Natural Gas     132     40.00 %   53   PNM     2020   BB-

 
Cadillac   Michigan   Biomass     40     100.00 %   40   Consumers Energy     2028   BBB-

 
Idaho Wind   Idaho   Wind     183     27.56 %   50   Idaho Power Co.     2030   BBB

 
Piedmont(11)   Georgia   Biomass     54     98.00 %   53   Georgia Power     2032   A

 

(1)
Except as otherwise noted, economic interest represents the percentage ownership interest in the project held indirectly by Atlantic Power.
(2)
Represents our interest in each project's electric generation capacity based on our economic interest.
(3)
Includes a separate power sales agreement in which the project and Atlantic City Electric ("ACE") share profits on spot sales of energy and capacity not purchased by ACE under the base PPA.
(4)
California utilities pay transmission access charges to the California Independent System Operator, who then pays owners of Transmission system rights, such as Path 15, in accordance with its annual revenue requirement approved every three years by the Federal Energy Regulatory Commission ("FERC").
(5)
Path 15 is a FERC regulated asset with a FERC-approved regulatory life of 30 years: through 2034.
(6)
Largest payers of transmission access charges supporting Path 15's annual revenue requirement are Pacific Gas & Electric (BBB+), Southern California Edison (BBB+) and San Diego Gas & Electric (A). The California Independent System Operator imposes minimum credit quality requirements for any participants rated A or better unless collateral is posted per the California Independent System Operator imposed schedule.
(7)
Upon the expiry of the Reedy Creek PPA, the associated capacity and energy will be sold to PEF under the terms of the current agreement.
(8)
Fitch rating on Reedy Creek Improvement District bonds.
(9)
Represents our residual interest in the project after all priority distributions are paid to us and the other partners, which is estimated to occur in 2012.
(10)
Entered into a one-year interim agreement in April 2011.
(11)
Project currently under construction and is expected to be completed in late 2012.

Schedule II-30


Table of Contents


Results of Operations

        The following table and discussion is a summary of our consolidated results of operations for the three and six month periods ended June 30, 2011 and 2010. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

 
  Three months ended
June 30,
  Six months ended
June 30,
 
(Unaudited)
(in thousands of U.S. dollars, except as otherwise stated)
  2011   2010   2011   2010  

Project revenue

                         
 

Auburndale

  $ 20,434   $ 19,570   $ 42,216   $ 40,037  
 

Lake

    16,844     17,842     33,968     34,083  
 

Pasco

    3,382     2,763     5,902     5,632  
 

Path 15

    7,491     7,729     15,135     15,373  
 

Other Project Assets

    5,107         9,702      
                   

    53,258     47,904     106,923     95,125  

Project expenses

                         
 

Auburndale

    13,787     14,089     30,215     30,133  
 

Lake

    10,710     12,810     21,634     24,007  
 

Pasco

    2,670     2,507     7,024     4,707  
 

Path 15

    2,310     2,762     5,357     5,452  
 

Chambers

            1      
 

Other Project Assets

    3,564     116     7,829     173  
                   

    33,041     32,284     72,060     64,472  

Project other income (expense)

                         
 

Auburndale

    (1,427 )   (1,012 )   (779 )   (5,695 )
 

Lake

    299     1,713     1,867     (6,220 )
 

Pasco

                 
 

Path 15

    (2,943 )   (3,096 )   (5,935 )   (6,242 )
 

Chambers

    1,649     1,654     4,704     5,103  
 

Other Project Assets

    (4,764 )   662     (6,820 )   1,806  
                   

    (7,186 )   (79 )   (6,963 )   (11,248 )

Total project income

                         
 

Auburndale

    5,220     4,469     11,222     4,209  
 

Lake

    6,433     6,745     14,201     3,856  
 

Pasco

    712     256     (1,122 )   925  
 

Path 15

    2,238     1,871     3,843     3,679  
 

Chambers

    1,649     1,654     4,703     5,103  
 

Other Project Assets

    (3,221 )   546     (4,947 )   1,633  
                   

    13,031     15,541     27,900     19,405  

Administrative and other expenses

                         
 

Administration

    4,671     3,843     8,725     7,943  
 

Interest, net

    3,510     2,518     7,478     5,312  
 

Foreign exchange loss (gain)

    (535 )   4,224     (1,193 )   2,432  
 

Other income, net

        (26 )       (26 )
                   

Total administrative and other expenses

    7,646     10,559     15,010     15,661  
                   

Income from operations before income taxes

    5,385     4,982     12,890     3,744  

Income tax expense (benefit)

    (7,684 )   3,618     (6,161 )   8,491  
                   

Net income (loss)

    13,069     1,364     19,051     (4,747 )

Net loss attributable to noncontrolling interest

    (117 )   (81 )   (271 )   (129 )
                   

Net income (loss) attributable to Atlantic Power Corporation shareholders

  $ 13,186   $ 1,445   $ 19,322   $ (4,618 )
                   

Schedule II-31


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Consolidated Overview

        We have six reportable segments: Auburndale, Chambers, Lake, Pasco, Path 15 and Other Project Assets. The results of operations are discussed below by reportable segment.

        Project income is the primary GAAP measure of our operating results and is discussed in "Project Operations Performance" below. In addition, an analysis of non-project expenses impacting our results is set out in "Administrative and Other Expenses (Income)" below.

        Significant non-cash items, which are subject to potentially significant fluctuations, include: (1) the change in fair value of certain derivative financial instruments that are required by GAAP to be revalued at each balance sheet date (see "Quantitative and Qualitative Disclosures About Market Risk" for additional information); (2) the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar denominated obligations and; (3) the related deferred income tax expense (benefit) associated with these non-cash items.

        Cash available for distribution was $18.0 million and $7.5 million for the three-months ended June 30, 2011 and 2010, respectively and $34.6 million and $25.3 million for the six-months ended June 30, 2011 and 2010, respectively. See "Cash Available for Distribution" in this Form 10-Q for additional information.

        Income from operations before income taxes for the three-months ended June 30, 2011 and 2010 was $5.4 million and $5.0 million, respectively and $12.9 million and $3.7 million for the six-months ended June 30, 2011 and 2010, respectively. See "Project Income" below for additional information.

Three months ended June 30, 2011 compared with three months ended June 30, 2010

Project Income

        The increase in project income for our Auburndale segment of $0.7 million to $5.2 million in the three-month period ended June 30, 2011 from income of $4.5 million in the comparable 2010 period is primarily attributable to the annual contractual escalation of capacity payments under the project's PPA, as well as favorable gas transportation cost compared to 2010.

        Project income for our Lake segment decreased $0.3 million to $6.4 million in the three-month period ended June 30, 2011, from income of $6.7 million in the comparable 2010 period. The decrease is primarily attributable to a $1.4 million change in the benefit associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. This was partially offset by lower fuel expenses attributable to lower prices on natural gas swaps.

        Project income for our Pasco segment increased $0.4 million to $0.7 million in the three-month period ended June 30, 2011, from project income of $0.3 million in the comparable 2010 period. The increase is due to higher dispatch compared to 2010 of the project.

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        Project income for our Path 15 segment increased $0.3 million to $2.2 million in the three-month period ended June 30, 2011 from $1.9 million in the comparable 2010 period due to decreased operation and maintenance costs.

        The change in project income for our Chambers segment, which is recorded under the equity method of accounting, was not significant in the three-month period ended June 30, 2011 compared to same period in 2010.

        Project income for our Other Project Assets segment decreased $3.7 million to a project loss of $(3.2) million for the three-month period ended June 30, 2011 compared to project income of $0.5 million in 2010. The most significant components to the change are as follows:

Administrative and Other Expenses (Income)

        Administration includes the non-project related costs of operating the company. Administration increased $0.9 million to $4.7 million in the three-month period ended June 30, 2011 from $3.8 million in the comparable 2010 period primarily due to higher business development costs associated with the CPILP transaction and increases in compensation costs attributable to an increase in corporate office staff levels.

        Interest expense at the corporate level primarily relates to our convertible debentures. Interest expense, net increased $1.0 million to $3.5 million in the three-month period ended June 30, 2011 from $2.5 million in the comparable 2010 period. This increase is due to the issuance of Cdn$80.5 million of convertible debentures in October of 2010.

        Foreign exchange loss (gain) primarily reflects the unrealized impact of changes in foreign exchange rates on the U.S. dollar equivalent of our Canadian dollar denominated obligations to holders of the convertible debentures. In addition, unrealized and realized gains and losses on our forward contracts for the purchase of Canadian dollars to satisfy these obligations and our dividends to shareholders are included in foreign exchange loss (gain). Unrealized gains and losses on our forward contracts are reclassified to realized gains and losses upon cash settlement of the contracts. Foreign exchange loss decreased $4.7 million to a $0.5 million gain in the three-month period ended June 30, 2011 compared to a $(4.2) million loss in the comparable 2010 period. The U.S. dollar to Canadian dollar exchange rate increased by 0.5% during the three-month period ended June 30, 2011, compared to a decrease of 4.6% in the comparable period in 2010. See Item 3 "Quantitative and Qualitative Disclosures About Market Risk" for additional details about our management of foreign currency risk

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and the components of the foreign exchange gain recognized during the three-month period ended June 30, 2011 compared to the foreign exchange loss in the comparable 2010 period.

Six months ended June 30, 2011 compared with six months ended June 30, 2010

Project Income

        The increase in project income for our Auburndale segment of $7.0 million to $11.2 million in the six-month period ended June 30, 2011 from income of $4.2 million in the comparable 2010 period is primarily attributable to the $4.6 million change in the benefit associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. Project revenue at Auburndale increased by $2.1 million in the six-month period ended June 30, 2011 due to favorable energy pricing compared to 2010, as well as the annual contractual escalation of capacity payments. Interest expense on project-level debt decreased by $0.3 million in the six-month period ended June 30, 2011 as compared to the comparable period in 2010.

        Project income for our Lake segment increased $10.3 million to $14.2 million in the six-month period ended June 30, 2011, from income of $3.9 million in the comparable 2010 period. The increase is primarily attributable to the $8.1 million change in the benefit associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. In addition, fuel costs at Lake decreased due to the lower price on natural gas swaps.

        Project income for our Pasco segment decreased $2.0 million to a project loss of $(1.1) million in the six-month period ended June 30, 2011, from project income of $0.9 million in the comparable 2010 period. The decrease is due to higher operations and maintenance expenses attributable to the unplanned replacement of gas turbine components during 2011.

        Project income for our Path 15 segment was consistent for the six-month period ended June 30, 2011and 2010.

        Project income for our Chambers segment, which is recorded under the equity method of accounting, decreased $0.4 million to $4.7 million in the six-month period ended June 30, 2011 from $5.1 million in the comparable 2010 period. The decrease in project income at Chambers is primarily attributable to lower dispatch compared to 2010.

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        Project income for our Other Project Assets segment decreased $6.5 million to a project loss of $(4.9) million for the six-month period ended June 30, 2011 compared to project income of $1.6 million in 2010. The most significant components to the change are as follows:

Administrative and Other Expenses (Income)

        Administration includes the non-project related costs of operating the company. Administration increased $0.8 million to $8.7 million for the six-month period ended June 30, 2011 from $7.9 million in the comparable 2010 period primarily due to higher business development costs associated with the CPILP transaction and increased compensation costs attributable to an increase in corporate office staff levels.

        Interest expense at the corporate level primarily relates to our convertible debentures. Interest expense, net increased $2.2 million to $7.5 million in the six-month period ended June 30, 2011 from $5.3 million in the comparable 2010 period. This increase is due to the issuance of Cdn$80.5 million of convertible debentures in October of 2010.

        Foreign exchange loss (gain) primarily reflects the unrealized impact of changes in foreign exchange rates on the U.S. dollar equivalent of our Canadian dollar-denominated obligations to holders of the convertible debentures. In addition, unrealized and realized gains and losses on our forward contracts for the purchase of Canadian dollars to satisfy these obligations and our dividends to shareholders are included in foreign exchange loss (gain). Unrealized gains and losses on our forward contracts are reclassified to realized gains and losses upon cash settlement of the contracts. Foreign exchange loss decreased $3.6 million to a $1.2 million gain in the six-month period ended 2011 compared to a $(2.4) million loss in the comparable 2010 period. The U.S. dollar to Canadian dollar exchange rate increased by 3.1% during the six-month period ended June 30, 2011, compared to a decrease of 1.3% in the comparable period in 2010. See Item 3 "Quantitative and Qualitative Disclosures About Market Risk" for additional details about our management of foreign currency risk and the components of the foreign exchange gain recognized during the six-month period ended June 30, 2011 compared to the foreign exchange loss in the comparable 2010 period.

Supplementary Non-GAAP Financial Information

        The key measure we use to evaluate the results of our projects is Cash Available for Distribution. Cash Available for Distribution is not a measure recognized under GAAP, does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. We believe Cash Available for Distribution is a relevant supplemental measure of our

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ability to pay dividends to our shareholders. A reconciliation of net cash provided by operating activities to Cash Available for Distribution is set out below under "Cash Available for Distribution." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

        The primary factor influencing Cash Available for Distribution is cash distributions received from the projects. These distributions received are generally funded from Project Adjusted EBITDA generated by the projects, reduced by project-level debt service and capital expenditures, and adjusted for changes in project-level working capital and cash reserves. Project Adjusted EBITDA is defined as project income plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use unaudited Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. A reconciliation of project income to Project Adjusted EBITDA is set out below under "Project Adjusted EBITDA." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

        Because Project Adjusted EBITDA and project distributions are key drivers of both the performance of our projects and Cash Available for Distribution, please see the following supplementary unaudited non-GAAP information that summarizes Project Adjusted EBITDA by project and a reconciliation of Project Adjusted EBITDA by project to project distributions actually received by us.

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Project Adjusted EBITDA (in thousands of U.S. dollars):

 
  Three months ended
June 30,
  Six months ended
June 30,
 
(unaudited)
  2011   2010   2011   2010  

Project Adjusted EBITDA by individual segment

                         
 

Auburndale

  $ 11,606   $ 10,431   $ 21,919   $ 19,802  
 

Lake

    8,424     7,299     16,914     14,612  
 

Pasco

    1,469     1,002     392     2,417  
 

Path 15

    7,186     7,062     13,756     14,115  
 

Chambers

    4,307     4,141     9,031     10,129  
                   

Total

    32,992     29,935     62,012     61,075  

Other Project Assets

                         
 

Selkirk

    3,206     3,526     4,314     7,056  
 

Orlando

    1,202     1,870     3,093     3,671  
 

Cadillac

    2,644         4,391      
 

Gregory

    956     1,428     1,728     2,283  
 

Idaho Wind

    1,246         2,051      
 

Badger Creek

    41     774     801     1,510  
 

Delta Person

    443     540     842     904  
 

Koma Kulshan

    374     434     434     553  
 

Rollcast

    (306 )       (773 )    
 

Piedmont

    (32 )       (61 )    
 

Topsham

        548         963  
 

Rumford

        1         (7 )
 

Other

    88     (530 )   15     (733 )
                   

Total adjusted EBITDA from Other Project Assets segment

    9,862     8,591     16,835     16,200  

Total adjusted EBITDA from all Projects

    42,854     38,526     78,847     77,275  

Depreciation and amortization

    17,661     16,596     35,098     32,982  

Interest expense, net

    7,088     6,097     13,328     11,878  

Change in the fair value of derivative instruments

    4,826     210     2,042     12,729  

Other (income) expense

    248     82     479     281  
                   

Project income as reported in the statement of operations

  $ 13,031   $ 15,541   $ 27,900   $ 19,405  
                   

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Reconciliation of Project Distributions (in thousands of U.S. dollars)
For the six months ended June 30, 2011

 
  Project
Adjusted
EBITDA
  Repayment
of debt
  Interest
expense,
net
  Capital
expenditures
  Change in
working
capital &
other items
  Project
distribution
received
 

Reportable Segments

                                     
 

Auburndale

  $ 21,919   $ (4,900 ) $ (595 ) $ (5 ) $ (1,619 ) $ 14,800  
 

Chambers

    9,031     (6,398 )   (2,801 )       168      
 

Lake

    16,914         5     (447 )   2,392     18,864  
 

Pasco

    392             (39 )   452     805  
 

Path 15

    13,756     (3,541 )   (5,934 )       (2,019 )   2,262  
                           

Total Reportable Segments

    62,012     (14,839 )   (9,325 )   (491 )   (626 )   36,731  
                           

Other Project Assets

                                     
 

Selkirk

    4,314     (5,354 )   (777 )   (3 )   5,974     4,154  
 

Orlando

    3,093         2     (118 )   (952 )   2,025  
 

Cadillac

    4,391     (1,150 )   (1,317 )   (62 )   (662 )   1,200  
 

Gregory

    1,728     (838 )   (231 )   (44 )   51     666  
 

Idaho Wind

    2,051     (33,237 )   (1,522 )       33,917     1,209  
 

Badger Creek

    801         (3 )       562     1,360  
 

Delta Person

    842     (555 )   (120 )       (167 )    
 

Koma Kulshan

    434                 (55 )   379  
 

Rollcast

    (773 )           (4 )   777      
 

Piedmont

    (61 )               61      
 

Other

    15         (35 )   40     180     200  
                           

Total Other Project Assets Segment

    16,835     (41,134 )   (4,003 )   (191 )   39,686     11,193  
                           

Total all Segments

  $ 78,847   $ (55,973 ) $ (13,328 ) $ (682 ) $ 39,060   $ 47,924  
                           

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Reconciliation of Project Distributions (in thousands of U.S. dollars)
For the six months ended June 30, 2010

 
  Project
Adjusted
EBITDA
  Repayment
of debt
  Interest
expense,
net
  Capital
expenditures
  Change in
working
capital &
other items
  Project
distribution
received
 

Reportable Segments

                                     
 

Auburndale

  $ 19,802   $ (4,900 ) $ (886 ) $ (8 ) $ (1,008 ) $ 13,000  
 

Chambers

    10,129     (6,026 )   (3,327 )   (34 )   (742 )    
 

Lake

    14,612         6     (1,004 )   748     14,362  
 

Pasco

    2,417             (467 )   380     2,330  
 

Path 15

    14,115     (3,740 )   (6,242 )       181     4,314  
                           

Total Reportable Segments

    61,075     (14,666 )   (10,449 )   (1,513 )   (441 )   34,006  
                           

Other Project Assets

                                     
 

Selkirk

    7,056     (4,657 )   (1,181 )   (309 )   (909 )    
 

Orlando

    3,671         1     (66 )   (1,706 )   1,900  
 

Gregory

    2,283     (823 )   (112 )   (39 )   (443 )   866  
 

Badger Creek

    1,510         (7 )       138     1,641  
 

Delta Person

    904     (1,023 )   (137 )       256      
 

Koma Kulshan

    553                 (206 )   347  
 

Rumford

    (7 )               7      
 

Topsham

    963                     963  
 

Other

    (733 )       7     (40 )   792     26  
                           

Total Other Project Assets Segment

    16,200     (6,503 )   (1,429 )   (454 )   (2,071 )   5,743  
                           

Total all Segments

  $ 77,275   $ (21,169 ) $ (11,878 ) $ (1,967 ) $ (2,512 ) $ 39,749  
                           

Project Operations Performance—Three months ended June 30, 2011 compared with three months ended June 30, 2010

        Aggregate Project Adjusted EBITDA increased $4.4 million to $42.9 million in the three-month period ended June 30, 2011 from $38.5 million in the comparable 2010 period and included the following factors:

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        Aggregate power generation for projects in operation for the three-months ended June 30, 2011 was 8.8% greater than the three-month period ended June 30, 2010. Generation during the three-month period ended June 30, 2011 compared to the comparable 2010 period was favorably impacted primarily by additional generation associated with the acquisition of Cadillac in the fourth quarter of 2010 and with Idaho Wind achieving commercial operation in the first quarter of 2011, as well as increased dispatch at Selkirk and Pasco. The favorable variance was partially offset by lower generation at Chambers and Badger Creek due to reduced dispatch, and at Lake which had no off-peak deliveries and a planned major maintenance outage at Orlando in 2011.

        The project portfolio achieved a weighted average availability of 95.5% for the three-month period ended June 30, 2011 compared to 95.2% in the 2010 period. The increase in portfolio availability for the three-month period ended June 30, 2011 versus the prior period was primarily due to a planned outage at Selkirk completed in 2010 offset by outages at Orlando and Badger Creek in 2011. Each of the projects with reduced availability was nevertheless able to achieve substantially all of their respective capacity payments as a result of contract terms that provide for certain levels of planned and unplanned outages.

Project Operations Performance—Six months ended June 30, 2011 compared with six months ended June 30, 2010

        Aggregate Project Adjusted EBITDA increased $1.6 million to $78.9 million in the six-month period ended June 30, 2011 from $77.3 million in the comparable 2010 period and included the following factors:

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        Aggregate power generation for projects in operation for the six-months ended June 30, 2011 was 4.6% greater than the six-month period ended June 30, 2010. Generation during the six-month period ended June 30, 2011 was favorably impacted primarily by additional generation associated with the acquisition of Cadillac in the fourth quarter of 2010 and with Idaho Wind achieving commercial operation in the first quarter of 2011, as well as increased dispatch at Selkirk. The favorable variance was partially offset by lower generation at Chambers and Badger Creek due to reduced dispatch and a planned major maintenance outage at Orlando in 2011 and increased generation at Lake associated with off-peak energy sales in 2010.

        The project portfolio achieved a weighted average availability of 94.6% for the six-month period ended June 30, 2011 compared to 96.7% in the 2010 period. The decrease in portfolio availability for the six-month period ended June 30, 2011 versus the prior period was primarily due to planned outages at Badger Creek, Chambers and Selkirk and a forced outage at Delta-Person. Each of the projects with reduced availability was nevertheless able to achieve substantially all of their respective capacity payments as a result of contract terms that provide for certain levels of planned and unplanned outages.


Cash Flow from Operating Activities

        Our cash flow from the projects may vary from year to year based on, among other things, changes in prices under the PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, changes in regulated transmission rates, compliance with the terms of non-recourse project-level financing including debt repayment schedules, the transition to market or re-contracted pricing following the expiration of PPAs, fuel supply and transportation contracts, working capital requirements and the operating performance of the projects. Project cash flows may have some seasonality and the pattern and frequency of distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.

        Cash flow from operating activities increased by $8.7 million for the six-month period ended June 30, 2011 over the comparable period in 2010. The changes from the prior period are partially attributable to the changes in Project Adjusted EBITDA described above, the release of $4.2 million of previously restricted cash at our equity accounted Selkirk project, as well as changes in working capital at both consolidated and unconsolidated affiliates.


Cash Flow from Investing Activities

        Cash flow from investing activities includes restricted cash. Restricted cash fluctuates from period to period in part because non-recourse project-level financing arrangements typically require all operating cash flow from the project to be deposited in restricted accounts and then released at the time that principal payments are made and project-level debt service coverage ratios are met. As a result, the timing of principal payments on project-level debt causes significant fluctuations in restricted cash balances, which typically benefits investing cash flow in the second and fourth quarters of the year and decreases investing cash flow in the first and third quarters of the year.

        Cash flows used in investing activities for the six-month period ended June 30, 2011 were $24.8 million compared to cash flows used in investing activities of $1.9 million for the comparable 2010 period. We invested $42.4 million for the construction-in-progress for our Piedmont biomass project offset by the repayment of $15.5 million from our related party loan to Idaho Wind.

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Cash Flow from Financing Activities

        Cash used in financing activities for the six-month period ended June 30, 2011 resulted in a net outflow of $18.8 million compared to a net outflow of $20.7 million for the same period in 2010. The change from the comparable period is primarily attributable to a $6.7 million increase in dividends paid due to a higher number of common shares outstanding to the comparable period in 2010. Since the year ended December 31, 2010, Cdn$17.2 million of convertible debentures have converted to common stock. In addition, we issued common shares in a public offering in October 2010. The increase in dividends is partially offset by proceeds of $29.9 million of project-level debt related to our Piedmont biomass project.


Cash Available for Distribution

        Holders of our common shares receive monthly cash dividends at an annual rate of Cdn$1.094 per share. Total dividends paid to shareholders for the three and six-month periods ended June 30, 2011 increased over the respective prior year amounts as a result of (i) increases in the value of the Canadian dollar, which is the currency in which the dividends are paid; and (ii) a higher number of common shares outstanding in the 2011 periods as a result of the conversion of convertible debentures into common shares and the issuance of vested shares from our long-term incentive plan. This increase in dividends paid is generally offset by realized gains on our foreign currency forward contracts, which are included in cash flows from operating activities. See "Foreign Currency Exchange Rate Risk" in Item 3 of this Form 10-Q for additional information about our foreign currency forward contracts. The payout ratio for the three-month periods ended June 30, 2011 and 2010 was 109% and 212%, respectively and 111% and 125% for the six-month periods ended June 30, 2011 and 2010, respectively.

        The table below presents our calculation of cash available for distribution for the three and six-month periods ended June 30, 2011 and 2010:

 
  Three months ended
June 30,
  Six months ended
June 30,
 
(unaudited)
(in thousands of U.S. dollars, except as otherwise stated)

  2011   2010   2011   2010  

Cash flows from operating activities

  $ 24,368   $ 15,139   $ 44,715   $ 35,978  

Project-level debt repayments

    (6,941 )   (6,441 )   (10,341 )   (9,141 )

Purchases of property, plant and equipment(1)

    (238 )   (1,201 )   (546 )   (1,520 )

Transaction costs(2)

    768         768      
                   

Cash Available for Distribution(3)

    17,957     7,497     34,596     25,317  

Total dividends to shareholders

   
19,550
   
15,913
   
38,542
   
31,714
 

Payout ratio

   
109

%
 
212

%
 
111

%
 
125

%

Expressed in Cdn$

                         

Cash Available for Distribution

    17,376     7,710     33,793     26,187  

Total dividends to shareholders

   
18,763
   
16,556
   
37,386
   
33,083
 

(1)
Excludes construction-in-progress related to our Piedmont biomass project.

(2)
Represents business development costs associated with the CPILP acquisition.

(3)
Cash Available for Distribution is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP. Therefore, this measure may not be comparable to similar measures presented by other companies. See "Supplementary Non-GAAP Financial Information".

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Outlook

        Based on our actual performance to date and projections for the remainder of the year, we continue to expect to receive distributions from our projects in the range of $80 million to $90 million for the full year 2011. We expect overall levels of operating cash flows in 2011 to be improved over actual 2010 levels. Higher distributions from existing projects, initial distributions from our recent investment in Idaho Wind and Cadillac, and a slightly lower payment under the management termination agreement are expected to be partially offset by the one-time cash tax refund of $8.0 million received in 2010. In 2012, additional increases in distributions from projects are expected to further increase operating cash flow compared to 2011. The most significant factor in the expected higher operating cash flow in 2012 is increased distributions from Selkirk following the final payment of its non-recourse project-level debt in 2012.

        The following items comprise the most significant increases in projected 2011 project distributions compared to 2010:

        In 2010, the following five projects comprised approximately 90% of project distributions received: Auburndale, Lake, Orlando, Path 15 and Pasco. For 2011, we expect these same five projects to contribute approximately 85% of total project distributions.

        In addition to the items above, the following is a summary of other projections for project distributions in 2011 and beyond:

Lake

        The Lake project is exposed to changes in natural gas prices from the expiration of its natural gas supply contract on June 30, 2009 through to the expiration of its PPA in July 2013 that are not passed through its PPAs. We have executed a hedging strategy to mitigate this exposure by periodically entering into financial swaps that effectively fix the forward price of natural gas expected to be purchased at the project. These hedges are summarized in Item 3, "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-Q. We intend to continue, when appropriate, to evaluate opportunities to further mitigate natural gas price exposure at Lake in 2013, but do not intend to execute additional hedges at Lake for 2011 and 2012 because our natural gas exposure for those years is already substantially hedged.

        The variable energy revenues in the Lake project's PPA are indexed, in part, to the price of coal consumed by a specific utility plant in Florida, the Crystal River facility. The components of this coal price are proprietary to the utility, but we believe that the utility purchases coal for that plant under a combination of short to medium term contracts and spot market transactions.

        Coal prices used in the energy revenue component of the projected distributions from the Lake project incorporate a forecast of the applicable Crystal River facility coal cost provided by the utility based on their internal projections. The projected annual cash distributions change by approximately $1.0 million for every $0.25/Mmbtu change in the projected price of coal.

        We expect to receive distributions from the Lake project of approximately $30 million to $34 million in both 2011 and 2012. The increases in 2011 and 2012 over the $28.8 million of distributions in 2010 are primarily due to higher contractual capacity payments and lower hedged and unhedged natural gas prices than in 2010.

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Auburndale

        Based on the current forecast, we expect distributions from Auburndale of $25 million to $27 million per year from 2011 through 2013, when the project's current PPA expires. Distributions received from Auburndale in the 2011 through 2013 period will be impacted by projected coal and gas prices in the forecast period.

        The projected revenue from the Auburndale PPA contains a component related to the costs of coal consumed at the utility off-taker's Crystal River facility as described above for the Lake project. Because that mechanism does not pass through changes in the project's fuel costs, Auburndale's operating margin is exposed to changes in natural gas prices for approximately 20% of its natural gas requirements through the expiration of the project's gas supply contract. The remaining 80% of the project's fuel requirements are supplied under an agreement with fixed prices through its expiration in mid-2012. We have been executing a strategy to mitigate the future exposure to changes in natural gas prices at Auburndale by periodically entering into financial swaps that effectively fix the forward price of natural gas required at the project. These hedges are summarized in Item 3, "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-Q. The 2011 natural gas price exposure at Auburndale has been substantially hedged. We intend to continue, when appropriate, to evaluate opportunities to further mitigate natural gas price exposure at Auburndale in 2012 and 2013.

Orlando

        The PPA at the Orlando project extends through 2023. However, the project's natural gas supply agreement expires in 2013. Currently projected market prices for natural gas following the expiration of the current supply agreement are lower than the price of natural gas currently being purchased under the project's gas contract. As a result, we expect a significant increase in cash distributions from the Orlando project beginning in 2014. We have been executing a hedging strategy to reduce the market price risk associated with expected natural gas requirements at Orlando in 2014 and beyond. See "Item 3. Quantitative and Qualitative Disclosures About Market Risks" in this Form 10-Q for further details.


Liquidity and Capital Resources

Overview

        Our primary source of liquidity is distributions from our projects and availability under our revolving credit facility. A significant portion of the cash received from project distributions is used to pay dividends to our shareholders and interest on our outstanding convertible debentures. We may fund future acquisitions with a combination of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately placed bank or institutional non-recourse operating level debt.

        We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due.

        Other than the capital requirements stated below for the CPILP acquisition, we do not expect any additional material or unusual requirements for cash outflows for 2011 for capital expenditures or other required investments. We have contributed approximately $75.0 million to fund the equity portion of the construction costs for Piedmont. Approximately $59.0 million of this amount was contributed in the fourth quarter of 2010 and the remaining balance was paid in the quarter ending March 31, 2011. In addition, there are no debt instruments with significant maturities or refinancing requirements in 2011. See "Outlook" above for information about changes in expected distributions from our projects in 2011 and beyond.

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        We intend to finance the cash portion of the purchase price for the transaction with CPILP by issuing up to approximately Cdn$200.0 million of equity and up to approximately $425.0 million of debt through public and private offerings. However, in the event that such financing is not available on terms satisfactory to us, we have received a commitment letter, evidencing the commitment of a Canadian chartered bank and another financial institution to structure, arrange, underwrite and syndicate a senior secured credit facility consisting of a Tranche B Facility in the amount of $625 million, subject to the terms and conditions set forth therein.

Credit facility

        We maintain a credit facility with a capacity of $100 million, $50 million of which may be utilized for letters of credit. The credit facility matures in August 2012.

        The credit facility bears interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin between 1.5% and 3.35% that varies based on the credit statistics of one of our subsidiaries. As of June 30, 2011, the applicable margin was 1.5%. As of June 30, 2011, $48.6 million were issued in letters of credit, but not drawn, to support contractual credit requirements at eight of our projects.

        We must meet certain financial covenants under the terms of the credit facility, which are generally based on the cash flow coverage ratios and also require us to report indebtedness ratios to our lenders. The facility is secured by pledges of assets and interests in certain subsidiaries. We expect to remain in compliance with the covenants of the credit facility for at least the next 12 months.

Convertible Debentures

        In October 2006, we issued, in a public offering, Cdn$60 million aggregate principal amount of 6.25% convertible secured debentures, which we refer to as the 2006 Debentures. In 2009 the holders agreed to change the rate to 6.50% and extend the maturity date to 2014. The 2006 Debentures pay interest semi-annually on April 30 and October 31 of each year. The Debentures have a maturity date of October 31, 2014 and are convertible into approximately 80.6452 common shares per Cdn$1,000 principal amount of 2006 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per common share. The 2006 Debentures are secured by a subordinated pledge of our interest in certain subsidiaries and contain certain restrictive covenants. Through August 10, 2011, a cumulative Cdn$14.5 million of the 2006 Debentures have been converted to 1.2 million common shares. As of August 10, 2011 the 2006 Debentures balance is Cdn$45.2 million ($47.5 million).

        In December 2009, we issued, in a public offering, Cdn$86.25 million aggregate principal amount of 6.25% convertible unsecured subordinated debentures, which we refer to as the 2009 Debentures. The 2009 Debentures pay interest semi-annually on March 15 and September 15 of each year beginning September 15, 2010. The 2009 Debentures mature on March 15, 2017 and are convertible into approximately 76.9231 common shares per Cdn$1,000 principal amount of 2009 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$13.00 per common share. Through August 10, 2011, a cumulative Cdn$13.9million of the 2009 Debentures have been converted to 1.1 million common shares. As of August 10, 2011 the 2009 Debentures balance is Cdn$72.4 million ($76.1 million).

        In October 2010, we issued, in a public offering, Cdn$80.5 million aggregate principal amount of 5.60% convertible unsecured subordinated debentures, which we refer to as the 2010 Debentures. The 2010 Debentures pay interest semi-annually on June 30 and December 30 of each year beginning June 30, 2011. The 2010 Debentures mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion rate of 55.2486 common shares per Cdn$1,000 principal amount of debentures, representing an initial conversion price of approximately

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Cdn$18.10 per common share. As of August 10, 2011 the 2010 debentures balance is Cdn$80.5 million ($84.6 million).

Project-level debt

        The following table summarizes the maturities of project-level debt. The amounts represent our share of the non-recourse project-level debt balances at June 30, 2011 and exclude any purchase accounting adjustments recorded to adjust the debt to its fair value at the time the project was acquired. Certain of the projects have more than one tranche of debt outstanding with different maturities, different interest rates and/or debt containing variable interest rates. Project-level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. As of June 30, 2011, the covenants at the Delta-Person project and at Epsilon Power Partners are temporarily preventing those subsidiaries from making cash distributions to us. We expect to resume receiving distributions from Delta-Person and Epsilon Power Partners in 2012. All project-level debt is non-recourse to us and substantially the entire principal is amortized over the life of the projects' PPAs. The non-recourse holding company debt relating to our investment in Chambers is held at Epsilon Power Partners, our wholly-owned subsidiary. For the six-month period ended June 30, 2011, we have contributed approximately $0.5 million to Epsilon Power Partners for debt service payments on the holding company debt but do not anticipate any additional required contributions to Epsilon.

        The range of interest rates presented represents the rates in effect at June 30, 2011.

 
  Range of
Interest Rates
  Total
Remaining
Principal
Repayments
  2011   2012   2013   2014   2015   Thereafter  

Consolidated Projects:

                                               

Epsilon Power Partners

  7.40%   $ 35,732   $ 750   $ 1,500   $ 3,000   $ 5,000   $ 5,750   $ 19,732  

Piedmont(1)

  5.20%     29,891         29,891                  

Path 15

  7.9% - 9.0%     150,327     4,446     8,667     9,402     8,065     8,749     110,998  

Auburndale

  5.10%     16,800     4,900     7,000     4,900              

Cadillac

  6.02% - 8.0%     41,381     1,150     3,791     2,400     2,000     2,500     29,540  
                                   

Total Consolidated Projects

        274,131     11,246     50,849     19,702     15,065     16,999     160,270  

Equity Method Projects:

                                               

Chambers

  0.9% - 7.0%     69,398     5,647     12,176     10,783     5,780     5,213     29,799  

Delta-Person

  2.1%     9,966     575     1,212     1,300     1,394     1,495     3,990  

Selkirk

  9.0%     11,439     5,594     5,845                  

Gregory

  1.8% - 7.5%     13,510     1,342     1,399     2,007     2,170     2,268     4,324  

Idaho Wind(2)

  5.2% - 13.3%     50,703     8,429     1,848     1,892     2,049     2,136     34,349  
                                   

Total Equity Method Projects

        155,016     21,587     22,480     15,982     11,393     11,112     72,462  
                                   

Total Project-Level Debt

      $ 429,147   $ 32,833   $ 73,329   $ 35,684   $ 26,458   $ 28,111   $ 232,732  
                                   

(1)
The Piedmont debt outstanding is the inception to date balance on the construction debt funded by the related bridge loan. The terms of the Piedmont project-level debt refinancing include an $82.0 million construction and term loan and a $51.0 million bridge loan for approximately 95.0% of the stimulus grant expected to be received from the U.S. Treasury 60 days after the start of commercial operations. The $51.0 million bridge loan will be repaid in 2012 and repayment of the expected $82.0 million term loan will commence in 2013.

(2)
The Idaho Wind project-level credit facility is composed of two tranches, which include a $157.5 million construction loan that was converted to a 17-year term loan upon commercial operations, and a $83.2 million cash grant facility which was repaid in June with federal stimulus grant proceeds after completion of construction, The remaining costs of the project were funded with a combination of equity from the owners

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Restricted cash

        The projects generally have reserve requirements to support payments for major maintenance costs and project-level debt service. For projects that are consolidated, our share of these amounts is reflected as restricted cash on the consolidated balance sheet. At June 30, 2011, restricted cash at the consolidated projects totaled $21.0 million.


Capital Expenditures

        Capital expenditures for the projects are generally made at the project level using project cash flows and project reserves. Therefore, the distributions that we receive from the projects are made net of capital expenditures needed at the projects. The projects in which we have investments generally consist of large capital assets that have established commercial operations. Ongoing capital expenditures for assets of this nature are generally not significant because most major expenditures relate to planned repairs and maintenance and are expensed when incurred.

        In 2011, several of the projects have planned outages to complete maintenance work. The level of maintenance and capital expenditures is slightly higher than in 2010. During the second quarter of 2011, Badger Creek replaced the combustor section of its gas turbine, the cost of which was covered under the operations and maintenance fee to the project's operator. Orlando undertook a scheduled major overhaul of its gas turbine and a major overhaul of its steam turbine in the second quarter. A substantial portion of Orlando's outage costs are paid through monthly payments under the project's long-term maintenance agreement with Alstom Power. Lake took two planned outages in the second quarter to replace one of its gas turbines and a portion of the other with temporary engine components available under Lake's lease engine agreement with GE, which permits Lake to install replacement engines while the project's components are being repaired. The cost of the repairs to Lake's engines is expected to be covered under the services agreement with GE that provides for unplanned maintenance.

        In the six-month period ended June 30, 2011, we incurred approximately $45.6 million in capital expenditures for the construction of our Piedmont biomass project. For the remainder of 2011, we expect to incur approximately $62.5 million in capital expenditures related to the Piedmont project, with total project costs through expected completion in late 2012 of approximately $207.0 million. The project is being funded with an $82.0 million construction loan which will convert to a term loan upon commercial operation, a $51.0 million bridge loan and approximately $75.0 million of equity contributed by Atlantic Power. The bridge loan will be repaid from the proceeds of a federal stimulus grant which is expected to be received two months after achieving commercial operation.


Off-Balance Sheet Arrangements

        As of June 30, 2011, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of Regulation S-K.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and commodity prices, will affect our cash flows or the value of our holdings of financial instruments. The objective of market risk management is to minimize the impact that market risks have on our cash flows as described in the following paragraphs.

        Our market risk-sensitive instruments and positions have been determined to be "other than trading." Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in fuel commodity prices, currency exchange rates or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in fuel commodity prices, currency exchange rates or interest rates and the timing of transactions.


Fuel Commodity Market Risk

        Our current and future cash flows are impacted by changes in electricity, natural gas and coal prices. The combination of long-term energy sales and fuel purchase agreements is generally designed to mitigate the impacts to cash flows of changes in commodity prices by generally passing through changes in fuel prices to the buyer of the energy.

        The Lake project's operating margin is exposed to changes in the market price of natural gas until the expiration of its PPA on July 31, 2013. The Auburndale project purchases natural gas under a fuel supply agreement which provides approximately 80% of the project's fuel requirements at fixed prices through June 30, 2012. The remaining 20% is purchased at market prices and therefore the project is exposed to changes in natural gas prices for that portion of its gas requirements through the termination of the fuel supply agreement and 100% of its natural gas requirements from the expiration of the fuel contract in mid-2012 until the termination of its PPA at the end of 2013.

        We have executed a strategy to mitigate the future exposure to changes in natural gas prices at Lake and Auburndale by periodically entering into financial swaps that effectively fix the price of natural gas required at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheet at fair value. Changes in the fair value of the natural gas swaps at Lake and Auburndale, through June 30, 2009 were recorded in other comprehensive income (loss) as they were designated as a hedge of the risk associated with changes in market prices of natural gas. As of July 1, 2009, these natural gas swap hedges were de-designated and the changes in their fair value are recorded in change in fair value of derivative instruments in the consolidated statements of operations.

        In 2011, projected cash distributions at Auburndale would change by approximately $0.5 million per $1.00/Mmbtu change in the price of natural gas based on the current level of un-hedged natural gas volumes at the project. In 2011, projected cash distributions at Lake would change by approximately $0.8 million per $1.00/Mmbtu change in the price of natural gas based on the current level of un-hedged natural gas volumes at the project.

        Coal prices used in the revenue component of the projected distributions from the Lake and Auburndale projects incorporate a forecast of the applicable Crystal River facility coal cost provided by the utility based on their internal projections. The projected annual cash distributions from Lake and Auburndale combined would change by approximately $2.4 million for every $0.25/Mmbtu change in the projected price of coal.

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        The following table summarizes the hedge position related to natural gas needed to meet PPA requirements at Lake and Auburndale as of June 30, 2011 and August 10, 2011:

 
  2011   2012   2013  

Portion of gas volumes currently hedged:

                   
 

Lake:

                   
   

Contracted

             
   

Financially hedged

    78 %   90 %   83 %
               
   

Total

    78 %   90 %   83 %
               
 

Auburndale:

                   
   

Contracted

    80 %   0 %   0 %
   

Financially hedged

    13 %   32 %   79 %
               
   

Total

    93 %   32 %   79 %
               

Average price of financially hedged volumes (per Mmbtu)

                   
 

Lake

  $ 6.52   $ 6.90   $ 6.63  
 

Auburndale

  $ 6.68   $ 6.51   $ 6.92  

        In October 2010, we entered into natural gas swaps that are effective in 2014 and 2015. The natural gas swaps are related to our 50% share of expected fuel purchases at our Orlando project as its operating margin is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. These financial swaps effectively fix the price of 1.2 million Mmbtu of natural gas at the Orlando project at a weighted average price of $5.76/Mmbtu and represent approximately 25% of our share of the expected natural gas purchases at the project during 2014 and 2015.

        We expect cash distributions from Orlando to increase significantly following the expiration of the project's gas contract at the end of 2013 because both projected natural gas prices at that time and the prices in the natural gas swaps we have executed are lower than the price of natural gas being purchased under the project's gas contract.


Foreign Currency Exchange Rate Risk

        We use forward foreign currency contracts to manage our exposure to changes in foreign exchange rates, as we generate cash flow in U.S. dollars but pay dividends to shareholders and interest on convertible debentures predominately in Canadian dollars. Since our inception, we have had an established hedging strategy for the purpose of mitigating the currency risk impact on the long-term sustainability of our dividends to shareholders. We have executed this strategy by entering into forward contracts to purchase Canadian dollars at fixed rates of exchange to hedge approximately 86% of our expected dividend and convertible debenture interest payments through 2013. Changes in the fair value of the forward contracts partially offset foreign exchange gains or losses on the U.S. dollar equivalent of our Canadian dollar obligations. The forward contracts consist of (1) monthly purchases through the end of 2013 of Cdn$6.0 million at an exchange rate of Cdn$1.134 per U.S. dollar and (2) purchases in both April and October 2011 of Cdn$1.9 million at an exchange rate of Cdn$1.1075 per U.S. dollar.

        It is our intention to periodically consider extending the length of these forward contracts.

        The foreign exchange forward contracts are recorded at fair value based on quoted market prices and the estimation of our credit rating or the credit rating of our counterparties. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations.

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        The following table contains the components of recorded foreign exchange (gain) loss for the three and six-month periods ended June 30, 2011 and 2010:

 
  Three months ended
June 30,
  Six months ended
June 30,
 
 
  2011   2010   2011   2010  

Unrealized foreign exchange (gain) loss:

                         
 

Convertible debentures

  $ 1,317   $ (6,486 ) $ 6,632   $ (2,505 )
 

Forward contracts and other

    1,303     12,309     (2,133 )   7,704  
                   

    2,620     5,823     4,499     5,199  

Realized foreign exchange gains on forward contract settlements

    (3,155 )   (1,599 )   (5,692 )   (2,767 )
                   

  $ (535 ) $ 4,224   $ (1,193 ) $ 2,432  
                   

        The following table illustrates the impact on the fair value of our financial instruments of a 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar as of June 30, 2011:

Convertible debentures, at carrying value

  $ 20,970  

Foreign currency forward contracts

  $ (20,548 )

        On July 27, 2011, August 3, 2011 and August 5, 2011 we executed a series of financial transactions with an exercise date of January 18, 2012, to economically hedge a portion of the foreign currency exchange risk associated with the closing of the CPILP transaction.

        The July 27, 2011 transactions include a forward purchase of $32.0 million at $0.9460 per Cdn$1.00, a call option to purchase $84.7 million at $0.94565 per Cdn$1.00 and a put option to sell $116.7 million at $0.90 per Cdn$1.00. The August 3, 2011 transactions include a forward purchase of $76.0 million at $0.9665 per Cdn$1.00, a call option to purchase $14.5 million at $0.9665 per Cdn$1.00 and a put option to sell $90.5 million at $0.90 per Cdn$1.00. The August 5, 2011 transactions include a forward purchase of $81.2 million at $0.9872 per Cdn$1.00, a call option to purchase $9.3 million at $0.9872 per Cdn$1.00 and a put option to sell $90.5 million at $0.90 per Cdn$1.00.


Interest Rate Risk

        Changes in interest rates do not have a significant impact on cash payments that are required on our debt instruments as approximately 89% of our debt, including our share of the project-level debt associated with equity investments in affiliates, either bears interest at fixed rates or is financially hedged through the use of interest rate swaps.

        We have executed an interest rate swap at our consolidated Auburndale project to economically fix a portion of its exposure to changes in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Auburndale debt. The interest rate swap was executed in November 2009 and expires on November 30, 2013.

        We have an interest rate swap at our consolidated Cadillac project to economically fix a portion of its exposure to changes in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Cadillac debt. The interest rate swap expires on June 30, 2025.

        We executed two interest rate swaps at our consolidated Piedmont project to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements

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are not designated as hedges and changes in their fair market value are recorded in the statements of operations. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively.

        In accounting for cash flow hedges, gains and losses on the derivative contracts are reported in other comprehensive income, but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income. That is, for cash flow hedges, all effective components of the derivative contracts' gains and losses are recorded in other comprehensive income (loss), pending occurrence of the expected transaction. Other comprehensive income (loss) consists of those financial items that are included in "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets but not included in our net income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings until the expected transaction occurs.

        After considering the impact of interest rate swaps, a hypothetical change in the average interest rate of 100 basis points would change annual interest costs, including interest at equity investments, by approximately $0.7 million.

ITEM 4.    CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

        Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report on Form 10-Q.

Changes in Internal Controls over Financial Reporting

        There were no changes in our internal controls over financial reporting (as such term is defined in Rules 13a-15(f) under the Exchange Act) that occurred during the period covered by this report that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations over Internal Controls

        Our internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. However, internal controls over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

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PART II—OTHER INFORMATION

        

ITEM 1.    LEGAL PROCEEDINGS

        Our Lake project is currently involved in a dispute with Progress Energy Florida over off-peak energy sales in 2010. All amounts billed for off-peak energy during 2010 by the Lake project have been paid in full by Progress. The Lake project has filed a claim against Progress in which we seek to confirm our contractual right to sell off-peak energy at the contractual price for such sales. Progress filed a counter-claim against the Lake project, seeking, among other things, the return of amounts paid for off-peak power sales during 2010 and a declaratory order clarifying Lake's rights and obligations under the PPA. The Lake project has stopped dispatching during off-peak periods pending the outcome of the dispute. However, we strongly believe that the court will confirm our contractual right to sell off-peak power using the contractual price that was used during 2010 and that we will be able to continue such off-peak power sales for the remainder of the term of the PPA. We have not recorded any reserves related to this dispute and expect that the outcome will not have a material adverse effect on our financial position or results of operations.

        From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending as of June 30, 2011 which are expected to have a material adverse impact on our financial position or results of operations.

ITEM 1A.    RISK FACTORS

        Except to the extent additional factual information disclosed elsewhere in this Quarterly Report on Form 10-Q relates to such risk factors (including, without limitation, the matters discussed in Part I, "Item 2-Management's Discussion and Analysis of Financial Condition and Results of Operations"), there were no material changes to the risk factors disclosed in Part I, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2010.

ITEM 6.    EXHIBITS

Exhibit
Number
  Description
  2.1   Arrangement Agreement, dated as of June 20, 2011, among Capital Power Income L.P., CPI Income Services LTD., CPI Investments Inc. and Atlantic Power Corporation (incorporated by reference to the Current Report on Form 8-K filed on June 24, 2011).

 

31.1

 

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934

 

31.2

 

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934

 

32.1

 

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

32.2

 

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

101.INS

 

XBRL Instance Document.

 

101.SCH

 

XBRL Taxonomy Extension Schema.

 

101.CAL

 

XBRL Taxonomy Extension Calculation Linkbase.

 

101.DEF

 

XBRL Taxonomy Extension Definition Linkbase.

 

101.LAB

 

XBRL Taxonomy Extension Label Linkbase.

 

101.PRE

 

XBRL Taxonomy Extension Presentation Linkbase.

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SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: August 12, 2011

  Atlantic Power Corporation

 

By:

 

/s/ LISA J. DONAHUE


      Name:   Lisa J. Donahue

      Title:   Interim Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

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Schedule III

Annual Information Form of CPILP dated March 11, 2011


Table of Contents

LOGO

Annual Information Form

For the year ended December 31, 2010

March 11, 2011

Schedule III-1


Table of Contents

TABLE OF CONTENTS

PRESENTATION OF INFORMATION

  III-4

FORWARD-LOOKING INFORMATION

 
III-4

DEFINITION OF CERTAIN TERMS

 
III-6

THE PARTNERSHIP

 
III-8
 

CORPORATE STRUCTURE

 
III-8

GENERAL DEVELOPMENT OF THE BUSINESS

 
III-9
 

RELATIONSHIP WITH CAPITAL POWER

 
III-9
 

AMENDMENTS TO LIMITED PARTNERSHIP AGREEMENT

  III-9
 

THREE YEAR HISTORY

  III-10

BUSINESS OF THE PARTNERSHIP

 
III-11
 

POWER PLANT SUMMARY

 
III-11
 

POWER PURCHASE AGREEMENTS

  III-17
 

THERMAL SUPPLY AGREEMENTS

  III-22
 

FUEL PURCHASE AGREEMENTS

  III-23
 

PARTNERSHIP WASTE HEAT AGREEMENTS

  III-24
 

PERC MANAGEMENT ARRANGEMENTS

  III-25
 

EMPLOYEES OF THE PARTNERSHIP

  III-25
 

EXPANSION, ENHANCEMENT AND ACQUISITION OPPORTUNITIES

  III-26

RISK FACTORS

 
III-26

REGULATION

 
III-26

ENVIRONMENTAL MATTERS

 
III-31

COMPETITION

 
III-34

DISTRIBUTIONS OF THE PARTNERSHIP

 
III-35

DIVIDENDS OF SUBSIDIARY (CPEL)

 
III-35

CAPITAL STRUCTURE

 
III-36

RATINGS

 
III-38

MARKET FOR SECURITIES

 
III-40

MANAGEMENT OF THE PARTNERSHIP

 
III-40

Schedule III-2


Table of Contents

BOARD OF DIRECTORS AND EXECUTIVE OFFICERS

  III-41
 

AUDIT COMMITTEE

 
III-50
 

INDEPENDENT DIRECTORS COMMITTEE

  III-51
 

OTHER COMMITTEES

  III-51
 

DIRECTOR ORIENTATION AND CONTINUING EDUCATION

  III-51
 

ETHICS POLICY

  III-52

COMPENSATION DISCUSSION AND ANALYSIS

 
III-53

EXECUTIVE COMPENSATION

 
III-67

INDEBTEDNESS OF DIRECTORS AND EXECUTIVE OFFICERS

 
III-73

COMPENSATION OF THE BOARD OF DIRECTORS

 
III-73

PERFORMANCE GRAPH

 
III-76

CONFLICTS OF INTEREST

 
III-77

LEGAL PROCEEDINGS

 
III-77

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

 
III-78

VOTING SECURITIES AND PRINCIPAL HOLDERS OF VOTING SECURITIES

 
III-79

TRANSFER AGENT AND REGISTRAR

 
III-79

MATERIAL CONTRACTS

 
III-80

INTEREST OF EXPERTS

 
III-81

ADDITIONAL INFORMATION

 
III-81

SCHEDULE A—CAPITAL POWER INCOME L.P. AND SIGNIFICANT SUBSIDIARIES

 
III-82

SCHEDULE C—GOVERNANCE COMMITTEE TERMS OF REFERENCE

 
III-88

SCHEDULE D—AUDIT COMMITTEE TERMS OF REFERENCE

 
III-91

SCHEDULE E—INDEPENDENT DIRECTORS TERMS OF REFERENCE

 
III-98

SCHEDULE F—PRESIDENT'S TERMS OF REFERENCE

 
III-102

Schedule III-3


Table of Contents


PRESENTATION OF INFORMATION

        Unless otherwise noted, the information contained in this Annual Information Form (AIF) is given at or for the year ended December 31, 2010. Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian generally accepted accounting principles (GAAP).

        This AIF provides material information about the business and operations of Capital Power Income L.P. (the Partnership). Any reference to the Partnership, means Capital Power Income L.P. and its subsidiaries on a consolidated basis, except where otherwise noted or the context otherwise dictates.

        The "Business Risks" section of the Partnership's Management's Discussion and Analysis dated March 2, 2011 (MD&A), for the year ended December 31, 2010 is incorporated by reference into this AIF and can be found on SEDAR at www.sedar.com.

        All financial information presented in millions of Canadian dollars is rounded to the nearest million unless otherwise stated.


FORWARD-LOOKING INFORMATION

        Certain information in this AIF is forward-looking and related to anticipated financial performance, events and strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target" and "expect" or similar words suggest future outcomes. By their nature, such statements are subject to significant risks, assumptions and uncertainties, which could cause the Partnership's actual results and experience to be materially different than the anticipated results.

        In particular, forward-looking information and statements include: (i) the sustainability of distributions; (ii) planned capital expenditures at Southport in 2011 and the anticipated total cost of the North Carolina enhancement project, including capacity levels; (iii) anticipated completion of the Southport facility modifications and the impact of the Southport and Roxboro facility modifications on the operation and economic performance of the facilities and their emissions; (iv) expectations regarding the time at which the Partnership will make material cash income tax payments; (v) expectations on the throughput on the TransCanada Canadian Mainline and related expectations regarding waste heat availability at the Ontario facilities; (vi) expectations in respect of new power purchase agreements at the North Carolina facilities, including timing for their being finalized, and expectations with respect to the Partnership's long-term outlook for the North Carolina plants; (vii) expectations regarding the introduction of new emissions and other environmental regulations, when such regulations will come into force, and the costs to comply with, and other impacts of, current and anticipated emissions and other environmental regulations; (viii) the expected impact of transition to International Financial Reporting Standards; (ix) expectations of the timing of the process to review strategic alternatives and expectations that the Partnership will seek growth opportunities that fit the Partnership's strategy and deliver on business plan priorities; (x) the monthly distributions of the Partnership while the strategic review process is underway; (xi) expectations regarding the final capital cost of the Oxnard natural gas turbine replacement, and reductions in forced outage costs at Oxnard in comparison to the previous turbine; (xii) expectations regarding the quantity and duration of new wood waste supply for Calstock; (xiii) expectations regarding Ontario Power Authority as a counterparty for replacement power purchase agreements; (xiv) expectations regarding demand growth for power in Canada and the U.S., and the need for new power development; and (xv) expectations regarding the Colorado Public Utilities Commission decision in December 2010, and the filing by parties of Requests for Rehearing and Reconsideration Applications in relation thereto.

        These statements are based on certain assumptions and analysis made by the Partnership in light of its experience and perception of historical trends, current conditions and expected future

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developments and other factors it believes are appropriate. The material factors and assumptions used to develop these forward-looking statements include, but are not limited to: (i) the Partnership's operations, financial position, available credit facilities and access to capital markets; (ii) the Partnership's assessment of commodity, currency and power markets; (iii) the markets and regulatory environment in which the Partnership's facilities operate; (iv) the state of capital markets; (v) management's analysis of applicable tax legislation; (vi) the assumption that the currently applicable and proposed tax laws will not change and will be implemented; (vii) the assumption that counterparties to fuel supply, power purchase agreements will continue to perform their obligations under the agreements taking account of the matters described herein; (viii) that current expectations regarding throughput on the TransCanada Canadian Mainline will continue; (ix) the level of plant availability and dispatch; (x) the performance of contractors and suppliers; (xi) the renewal or replacement of power purchase and other agreements including the terms and timing of power purchase agreements at the North Carolina facilities; (xii) the ability of the Partnership to successfully realize the benefits of its capital projects; (xiii) the ability of the Partnership to implement its strategic initiatives and whether such initiatives will yield the expected benefits; (xiv) expected water flows; (xv) the ability of the Partnership to adequately source alternative sources of supply of wood waste; (xvi) currently applicable and proposed environmental regulation will be implemented; (xvii) the ability to manage the transition to IFRS; and (xviii) the Partnership's assessment of the strategic alternatives that may be available to it.

        Whether actual results, performance or achievements will conform to the Partnership's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from the Partnership's expectations. Such risks and uncertainties include, but are not limited to risks relating to (i) the operation of the Partnership's facilities; (ii) plant availability and performance; (iii) the availability and price of energy commodities including natural gas and wood waste; (iv) the performance of counterparties in meeting their obligations under fuel supply, power purchase and other agreements; (v) competitive factors in the power industry; (vi) economic conditions, including in the markets served by the Partnership's facilities; (vii) changing demand for natural gas transportation on the TransCanada Canadian Mainline; (viii) ongoing compliance by the Partnership with its current debt covenants; (ix) developments within the North American capital markets; (x) the availability and cost of permanent long term financing in respect of acquisitions and investments; (xi) unanticipated maintenance and other expenditures; (xii) the Partnership's ability to successfully realize the benefits of its capital projects; (xiii) changes in regulatory and government decisions including changes to emission regulations; (xiv) waste heat availability and water flows; (xv) changes in existing and proposed tax and other legislation in Canada and the U.S. and including changes in the Canada-U.S. tax treaty; (xvi) the tax attributes of and implications of any acquisitions; (xvii) the availability and cost of equipment; (xviii) the ability of the Partnership to adequately source alternative sources of supply of wood waste; (xix) the ability of the Partnership to obtain power purchase agreements for the North Carolina facilities with satisfactory financial terms; and (xx) the strategic review process could take more or less time than anticipated. See "Business Risks" in the Partnership's MD&A.

        Readers are cautioned not to place undue reliance on forward-looking statements as actual results could differ materially from the plans, expectations, estimates or intentions expressed in the forward-looking statements. Forward-looking statements are provided for the purpose of presenting information about management's current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. Except as required by law, the Partnership disclaims any intention and assumes no obligation to update any forward-looking statement.

Schedule III-5


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DEFINITION OF CERTAIN TERMS

        Certain terms used in this AIF are defined below:

"BC Hydro" means British Columbia Hydro and Power Authority

"Board" or "Board of Directors" means the board of directors of CPI Income Services Ltd., the General Partner

"Btu" means British thermal units

"Capital Power" means Capital Power Corporation together with its subsidiaries and its investment in Capital Power L.P. on a consolidated basis except where otherwise noted or the context otherwise dictates

"CHP" means combined heat and power

"CoA" means Certificate of Approval

"Common Shares" means common shares of Capital Power Corporation

"Capital Power CGCN Committee" means the Corporate Governance, Compensation & Nomination Committee of Capital Power Board of Directors

"CPEL" means CPI Preferred Equity Ltd.

"CPI Investments" means CPI Investments Inc.

"CPUC" means California Public Utility Commission

"CPUSGP" means CPI Power (US) GP

"DB" means defined benefit

"DBRS" means DBRS Limited

"DC" means defined contribution

"EBIT" means Earnings Before Interest & Taxes

"EPA" means Electricity Purchase Agreement

"EPCOR" means EPCOR Utilities Inc. collectively with its subsidiaries

"Equistar" means Equistar Chemicals, LP

"ESA" means Energy Supply Agreement

"EWG" means Exempt Wholesale Generator

"FERC" means Federal Energy Regulatory Commission

"FPA" means Fuel Purchase Agreement

"General Partner" means CPI Income Services Ltd., the general partner of the Partnership

"GWh" means gigawatt hours

"HRSG" means heat recovery steam generator

"IFRS" means International Financial Reporting Standards issued by the International Accounting Standards Board

"kWh" means kilowatt hours

"LAPP" means Local Authorities Pension Plan

Schedule III-6


Table of Contents

"lbs/hr" means pounds per hour

"LTIP" means long-term incentive plan

"Management and Operations Agreements" means collectively certain management and operations agreements with the Manager as described in the "Management of the Partnership" and "Interests of Management and Others in Material Transactions" sections of this AIF

"Manager" means CP Regional Power Services Limited Partnership and Capital Power Operations (USA) Inc., both subsidiaries of Capital Power

"mlbs/hr" means thousand pounds per hour

"MW" means megawatts

"MWh" means megawatt hours

"NEO" means Named Executive Officer

"NOx" means nitrogen oxide

"NUSC" means Negotiated Utility Service Contracts

"OEFC" means Ontario Electricity Financial Corporation

"Partnership" means Capital Power Income L.P. and its subsidiaries on a consolidated basis, except where otherwise noted or the context otherwise dictates

"PERC" means Primary Energy Recycling Corporation

"PERH" means Primary Energy Recycling Holdings LLC

"PPA" means Power Purchase Agreement

"PSCo" means Public Service Company of Colorado

"QF" means Qualifying Facility

"RFP" means Request for Proposal

"ROCE" means Return on Capital Employed

"S&P" means Standard & Poor's, a division of the McGraw-Hill Companies (Canada) Corporation

"SCE" means Southern California Edison Company

"SDG&E" means San Diego Gas and Electric Company

"SEDAR" means the System for Electronic Document Analysis and Retrieval, which can be accessed via the Internet at www.sedar.com

"Series 1 Shares" means the Cumulative Redeemable Preferred Shares, Series 1 issued by CPEL

"Series 2 Shares" means the Cumulative Rate Reset Preferred Shares, Series 2 issued by CPEL

"Series 3 Shares" means the Cumulative Floating Rate Preferred Shares, Series 3 issued by CPEL

"SO2" means sulphur dioxide

"SPP" means Supplemental Pension Plan

"STIP" means short-term incentive plan

"SPA" means Steam Purchase Agreement

"SRAC" means short run avoided cost

Schedule III-7


Table of Contents

"The Navy" means the United States Navy

"TransCanada" means TransCanada PipeLines Limited

"TSA" means Thermal Supply Agreement

"TSX" means Toronto Stock Exchange

"Unitholders" means holders of Units

"Units" means limited partnership units of the Partnership

"U.S." means United States of America

"Ventures" means CPI USA Ventures LLC


THE PARTNERSHIP

        The Partnership (formerly known as EPCOR Power L.P. and prior thereto, TransCanada Power, L.P.) was formed pursuant to a limited partnership agreement (the Partnership Agreement) dated as of March 27, 1997 and as amended and restated June 6, 1997 and as amended September 29, 1998, March 26, 2004, April 29, 2004 and August 31, 2005 and as amended and restated July 1, 2009, October 1, 2009 and November 4, 2009 among CPI Income Services Ltd. hereinafter referred to as the General Partner (formerly known as TransCanada Power Services Ltd.), the initial limited partner and each person who is admitted to the Partnership as a limited partner in accordance with the terms of the Partnership Agreement. On March 27, 1997, the Partnership was registered as a limited partnership under the laws of the Province of Ontario and was registered or extra-provincially registered, as the case may be, in all other provinces of Canada. The head office of the Partnership is located at 10065 Jasper Avenue, Edmonton, Alberta, T5J 3B1. The registered office of the Partnership is 200 University Avenue, Toronto, Ontario, M5H 3C6.

        The Partnership is only permitted to carry on activities that are directly or indirectly related to the energy supply industry and to hold investments in other entities which are primarily engaged in such industry. As at December 31, 2010, the Partnership's portfolio consisted of 19 wholly-owned power generation assets located in both Canada (in the provinces of British Columbia and Ontario) and in the United States (in the states of California, Colorado, Illinois, New Jersey, New York, and North Carolina), a 50.15% interest in a power generation asset in Washington State (collectively the power plants), and a 14.3% common equity interest in Primary Energy Recycling Holdings LLC (PERH). See "General Development of the Business".

        The General Partner is responsible for the management of the Partnership. The General Partner has engaged CP Regional Power Services Limited Partnership and Capital Power Operations (USA) Inc., both subsidiaries of Capital Power Corporation (Capital Power), to perform management and administrative services for the Partnership and to operate and maintain the power plants pursuant to the Management and Operations Agreements. See "Management of the Partnership" and "Interests of Management and Others in Material Transactions".


Corporate Structure

        The Partnership's corporate structure is shown on Schedule A of this AIF.

Schedule III-8


Table of Contents


GENERAL DEVELOPMENT OF THE BUSINESS

Relationship with Capital Power

        As part of the sale by EPCOR Utilities Inc. (EUI, and collectively with its subsidiaries, EPCOR) of a 27.8% interest in its power generation business to Capital Power: (i) in June 2009, CPI Investments Inc. (CPI Investments) acquired 16,511,104 limited partnership units (Units) in the capital of the Partnership and all of the common shares of the General Partner of the Partnership, which entity directly owns 2,400 Units in the capital of the Partnership, representing collectively 30.6% of the then total outstanding units of the Partnership (the Acquisition), and (ii) in July 2009, Capital Power acquired 100% ownership of the entities that provide management and operations services to the Partnership and its subsidiaries pursuant to the Management and Operations Agreements. EPCOR owns 51 voting, non-participating shares of CPI Investments and Capital Power indirectly owns 49 voting, participating shares of CPI Investments. Pursuant to the Shareholder Agreement in respect of CPI Investments, Capital Power L.P. and EPCOR agreed that: (i) the board of directors of CPI Investments shall consist of three directors; and (ii) EPCOR is entitled to nominate one person for election to the board of directors of CPI Investments.

        In connection with the Acquisition, the Partnership, Capital Power and EUI entered into a Memorandum of Agreement dated June 7, 2009, pursuant to which the parties agreed on certain matters, including: (i) an approach by which Capital Power and the Partnership will work together early in the process to review Capital Power development opportunities in which the Partnership might have an interest in participating and acquisitions under the Partnership's right of first look applicable to operating power generation acquisitions (including brownfield development opportunities tied to such assets) on which Capital Power plans to bid (including through joint venture opportunities); (ii) the Partnership will have a right of first look on the sale of Capital Power generation assets so it may become the acquiring vehicle at not less than the fair market value for such assets; (iii) amendments to the incentive fee pursuant to which the Manager is compensated by the Partnership, and (iv) the basis on which the Partnership would in the future provide relief to Capital Power with respect to maintaining its minimum 30% interest in the Partnership. See "Interests of Management and Others in Material Transactions" and "Material Contracts". In addition, the Partnership and each of EPCOR and Capital Power entered into standstill agreements pursuant to which Capital Power and EPCOR agreed not to increase their ownership in the Partnership without the consent of the Independent Directors of the Partnership until July 1, 2010.

        As a result of the Premium DistributionTM and Distribution Reinvestment Plan (the DRIP), as of December 31, 2010, CPI Investments, through its direct ownership of Units and 100% ownership of the General Partner, indirectly owned 29.6% of the outstanding Units.


TM
Denotes a trademark of Canaccord Capital Corporation

        As at December 31, 2010, the Partnership's assets, excluding its interests in PERH, had a total net generating capacity of 1,400 MW and more than four million pounds per hour of thermal energy.


Amendments to Limited Partnership Agreement

        In connection with the sale by EPCOR of its power generation business to Capital Power, effective July 1, 2009, the Limited Partnership Agreement governing the Partnership was amended and restated to reflect the acquisition by Capital Power from EPCOR of the ownership interests in the Partnership. In connection with the launch of the DRIP, effective October 1, 2009 the Limited Partnership Agreement was amended and restated to provide for distributions to limited partners on a monthly basis, and, as contemplated in the Memorandum of Agreement dated June 7, 2009, to provide relief to Capital Power with respect to maintaining its minimum 30% interest in the Partnership. See

Schedule III-9


Table of Contents


"Distributions of the Partnership". Effective November 4, 2009, the Limited Partnership Agreement was amended and restated to change the name of the Partnership to Capital Power Income L.P.


Three Year History

        The general development of the Partnership's business during the last three financial years, and the significant acquisitions and events or conditions which have had an influence on such development, are described below.


2010

        In November 2010, the Partnership completed the final phase of the enhancement project on the North Carolina facilities designed to reduce environmental emissions and improve economic performance by increasing the use of tire-derived fuel and wood waste in the fuel mix and significantly reducing the nitrogen oxide (NOx) and sulphur dioxide (SO2) emissions. Project costs incurred to December 31, 2010, including costs incurred prior to 2010, were US$82 million with an additional US$5 million to be spent in 2011 on access roads and final testing.

        On October 5, 2010, the Partnership and Capital Power announced that the Partnership had initiated a process to review its strategic alternatives. This decision was the result of separate strategic review processes undertaken by the Special Committee of the independent directors of the Board to maximize value for the Partnership's Unitholders and by Capital Power to maximize value for Capital Power's shareholders. The initiation of the strategic review was not in response to any proposed transaction for the Partnership and there is no assurance that it will lead to a transaction. During the process to review strategic alternatives it is anticipated that the Partnership will continue to provide the same amount of monthly distributions to its Unitholders, maintain the same investor proposition supported by its high quality portfolio of contracted power assets and deliver on business plan priorities.

        In July 2010, the Partnership filed a renewal of its Short Form Base Shelf Prospectus in each of the provinces and territories of Canada qualifying the issuance by the Partnership from time to time over a period of 25 months of up to $600 million in securities consisting of Units, debt securities and/or subscription receipts.

        In May 2010, the Partnership completed the replacement of the existing GE LM5000 natural gas turbine with a more efficient and reliable GE LM6000 at Oxnard at a cost of US$19.2 million. The final capital cost could potentially be lower if the sale of the used General Electric LM5000 turbine is successful. The repowering project was completed on May 21, 2010, in time for the summer peak demand season in Southern California.


2009:

        To December 31, 2009, the Partnership incurred a total of US$70.7 million on the enhancement project designed to reduce environmental emissions and improve the economic performance of the Southport and Roxboro facilities. Enhancements to the Roxboro facility and to one of the two units at the Southport facility were completed in December 2009.

        On November 2, 2009, CPI Preferred Equity Ltd. (CPEL), a subsidiary of the Partnership, issued 4,000,000 Cumulative Rate Reset Preferred Shares, Series 2 (Series 2 Shares) for gross proceeds of $100 million. The net proceeds were used to repay outstanding bank indebtedness. The Series 2 Shares are fully and unconditionally guaranteed by the Partnership on a subordinated basis as to: (i) the payment of dividends, as and when declared; (ii) the payment of amounts due on a redemption for cash; and (iii) the payment of amounts due on the liquidation, dissolution or winding up of CPEL. If, and for so long as, the declaration or payment of dividends on the Series 2 Shares is in arrears, the

Schedule III-10


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Partnership will not make any distributions on the Units. See "Dividends of Subsidiary (CPEL)" and "Capital Structure—Preferred Shares of CPEL" in this AIF and "Business Risks—Preferred Share guarantee—unit distribution risk" in the Partnership's MD&A.

        In August 2009, the Partnership converted all of its common and preferred interests in PERH to a 14.3% common equity interest in connection with a recapitalization of PERH, pursuant to which all previously outstanding common and preferred interests in PERH, including those held by the Partnership, were converted to new common equity interests. Primary Energy Recycling Corporation (PERC) completed its previously announced US$50 million rights offering in November 2009 and, concurrently with PERC's subscription for new common membership interests in PERH, the Partnership exercised its pre-emptive right to subscribe for additional common membership interests to maintain its current pro-rata interest (14.3%) in PERH at an aggregate subscription price of US$8.3 million. Concurrently with the PERH recapitalization, certain changes were made to the long-term management agreement pursuant to which a subsidiary of the Partnership provides certain management and administrative services to PERH, certain subsidiaries of PERH and PERC (PERC Management Agreement). See "Business of the Partnership—PERC Management Arrangements" and "Material Contracts".

        On May 26, 2009, the Partnership completed the sale of its 64 MW combined-cycle, natural gas and oil-fired Castleton power plant for approximately US$10.7 million.

        On May 1, 2009, the Partnership completed the repowering project for its North Island facility, which involved the replacement of its GE LM5000 natural gas turbine with a more efficient GE LM6000 unit at a cost of approximately US$17.0 million.


2008:

        On October 31, 2008, the Partnership, through an indirect wholly-owned subsidiary, acquired a 100% interest in Morris Cogeneration, LLC, which owns a 177 MW natural gas-fired cogeneration facility for total cash consideration of US$73.4 million.

        In July 2008, the Partnership filed a Short Form Base Shelf Prospectus in each of the provinces and territories of Canada qualifying the issuance by the Partnership from time to time over a period of 25 months of up to $1 billion in securities consisting of Units, debt securities and/or subscription receipts. Concurrent with the prospectus filing, a Prospectus Supplement was filed, establishing a Medium Term Notes program of up to $600 million as part of the overall prospectus limit.


BUSINESS OF THE PARTNERSHIP

        The Partnership's primary business is the ownership and operation of power plants in Canada and the United States, which generate electricity and steam, from which it derives its earnings and cash flows. The power plants generate electricity and steam from a combination of natural gas, waste heat, wood waste, water flow, coal and tire-derived fuel.


Power Plant Summary

        The Partnership's Canadian operations consist of:

        The Partnership's United States operations consist of:

Schedule III-11


Table of Contents

        The following two pages summarize each of the Partnership's 20 power plants and their operating characteristics.

Remainder of page left intentionally blank

Schedule III-12


Table of Contents

 
  Nipigon   Kapuskasing   North Bay   Tunis   Calstock   Williams Lake   Mamquam   Moresby Lake   Frederickson   Manchief

Electric Capacity(1)

  40 MW   40 MW   40 MW   43 MW   35 MW   66 MW   50 MW   6 MW   125 MW + 10 MW duct firing(5)   301 MW

Location

  Nipigon, Ontario   Kapuskasing, Ontario   North Bay, Ontario   Iroquois Falls, Ontario   Hearst, Ontario   Williams Lake, British Columbia   Mamquam River, British Columbia   Moresby Island, British Columbia   Pierce County, Washington   Brush, Colorado

Type

  Enhanced combined cycle gas-fired generation   Enhanced combined cycle gas-fired generation   Enhanced combined cycle gas-fired generation   Enhanced combined cycle gas-fired generation   Enhanced biomass wood waste generation   Biomass wood waste generation   Hydroelectric run-of-river   Hydroelectric reservoir-based station   Combined cycle gas-fired generation   Simple-cycle gas-fired generation

Major Equipment

  22 MW gas turbine, 18 MW steam turbine, 3 HRSGs   25 MW gas turbine, 20 MW steam turbine, 3 HRSGs   25 MW gas turbine, 20 MW steam turbine, 2 HRSGs   31 MW gas turbine, 17 MW steam turbine, 4 HRSGs   Wood waste boiler, 41 MW steam turbine, 2 HRSGs   Wood waste boiler, 66 MW steam turbine   2 hydroelectric turbines   3 hydroelectric turbines   166 MW combustion turbine, 88 MW steam turbine   2 gas turbines

Commercial Operations

  1992   1997   1997   1995   2000   1993   1996   1990   2002   2000

PPA Expiry

  2012(2)   2017   2017   2014   2020   2018 with an option for 2 extensions of 5 years each   2027(4) with an option to extend and purchase facility at the end of the term   2022   2022   2022(7)

Counterparty to PPAs

  OEFC   OEFC   OEFC   OEFC   OEFC   BCH   BCH   BCH   3 Public Utility Districts (PUDs)(6)   PSCo

FPA Expiry

  Gas supply agreements expiring 2012   Gas supply agreement expiring 2017   Gas supply agreement expiring 2017   Month to month   Wood waste agreements with three local mills expiring 2019   5 wood waste agreements expiring 2018. 1 wood waste agreement expiring 2014(3)           PUDs are responsible for fuel supply   PSCo is responsible for the fuel supply

Fuel Supply

  NAL, Petrobank   TCPM   TCPM       Tembec, Lecours, Columbia                    

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Table of Contents

The legal names of the respective counterparties are:
British Columbia Hydro and Power Authority (BCH)
Columbia Forest Products, Inc. (Columbia)
Devon Canada Corporation (Devon)
Lecours Lumber Co. Limited (Lecours)
NAL Resources Ltd. (NAL)
Ontario Electricity Financial Corporation (OEFC)
Petrobank Energy and Resources Ltd. (Petrobank)
Public Service Company of Colorado (PSCo)
Tembec Inc. (Tembec)
TransCanada Power Marketing Ltd. (TCPM)


Notes:

(1)
Electric capacity is shown as net generation.

(2)
The Partnership has the option to extend the PPA for 10 years at existing terms.

(3)
Several periodic suppliers continue to supply on an as available and needed basis. Several long-term suppliers have temporarily curtailed operations but the new 5-year agreement with Pioneer Biomass Inc. more than offsets the expected shortfall. See "Business Risks" in the MD&A

(4)
BCH has an option exercisable in 2021 and every five years thereafter to buy the Mamquam facility or extend the contract.

(5)
Represents Partnership's 50.15% ownership interest in Frederickson. Puget Sound Energy, Inc. owns the remaining 49.85% ownership interest.

(6)
Public Utility Districts are: Benton, Franklin and Grays Harbor.

(7)
PSCo has an option during the latter part of the extension term to purchase the Manchief facility.

Schedule III-14


Table of Contents

 
  Greeley   Naval Station   North Island   Naval Training Center   Oxnard   Curtis Palmer   Morris   Kenilworth   Roxboro   Southport

Electric Capacity(1)

  72 MW   47 MW   40 MW   25 MW   48 MW   60 MW   177 MW   30 MW   52 MW(5)   103MW(5)

Steam Capacity

  170 mlbs/hr   479 mlbs/hr   390 mlbs/hr   220 mlbs/hr   120 mlbs/hr       1,080 mlbs/hr   78 mlbs/hr   540 mlbs/hr   1,080 mlbs/hr

Location

  Greeley, Colorado   San Diego, California   San Diego, California   San Diego, California   Oxnard, California   Hudson River near Corinth, New York   Morris, Illinois   Kenilworth, New Jersey   Roxboro, North Carolina   Southport, North Carolina

Type

  Natural gas-fired CHP facility   Dual-fuel (natural gas or No. 2 distillate fuel oil) CHP facility   Natural gas-fired CHP facility   Dual-fuel (natural gas or No. 2 distillate fuel oil) CHP facility   Natural gas-fired CHP facility   Hydroelectric impoundment and run-of-river   Natural gas-fired CHP facility   Dual fuel (natural gas or No. 2 distillate fuel oil) CHP facility   Coal, tire-derived fuel and wood waste CHP facility   Coal, tire-derived fuel and wood waste CHP facility

Major Equipment

  Two 35 MW gas turbines, 12 MW steam turbine, 2 HRSGs   37 MW gas turbine, 10 MW steam turbine, 1 HRSG   36 MW gas turbine, 4 MW steam turbine, 1 HRSG   22 MW gas turbine, 2.5 MW steam turbine, 1 HRSG   49 MW gas turbine, 1 HRSG, 1 AAARP   7 turbines   3 combustion turbine-generators, 3 HRSGs, 60 MW steam turbine generator   23 MW gas turbine, 7 MW steam turbine, 1 HRSG   3 stoker boilers, 57.4 MW steam turbine   6 stoker boilers, two 57.4 MW steam turbines

Commercial Operations

  1988   1989   1989   1989   1990   1986(2)   1998   1989   2009(6)   2010(6)

PPA Expiry

  2013   2019   2019   2019   2020   2027 or delivery of 10,000 GWh   2023 (77 MW)
2011 (100 MW)
  2012   Under negotiation   Under negotiation

Counterparty to PPAs

  PSCo   SDG&E   SDG&E   SDG&E   SCE   Niagara   ECLP, EGC LLC   Schering   CP&L   CP&L

SPA Expiry

  2013   2018   2018   2018           2023   2012(3)       2014

Counterparty to SPAs

  UNC   U.S. Navy   U.S. Navy   U.S. Navy   Boskovich       ECLP   Schering       ADM

FPA Expiry

  Gas supply agreement expiring in 2011   Gas supply agreement expiring 2011   Gas supply agreement expiring 2011   Gas supply agreement expiring 2011   Gas supply agreement expiring 2011       Gas supply agreement expiring 2016   Month-to-
month gas supply
  Annual(7)   Annual(7)

Fuel Supply

  SENA   SETC   SETC   SETC   SETC       TPSC   SETC(4)        

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The legal names of the respective counterparties are:
Archer Daniels Midland Company (ADM)
Boskovich Farms, Inc. (Boskovich)
Carolina Power & Light Company (CP&L)
Equistar Chemicals, LP (ECLP)
Exelon Generation Company LLC (EGC LLC)
Niagara Mohawk Power Corporation (Niagara)
Public Service Company of Colorado (PSCo)
Public Service Enterprise Group (PSE&G)
San Diego Gas & Electric Company (SDG&E)
Schering-Plough Corporation (Schering)
Sempra Energy Trading Corporation (SETC)
Shell Energy North America (US), L.P. (SENA)
Southern California Edison Company (SCE)
Tenaska Power Services Co. (TPSC)
University of Northern Colorado (UNC)


Notes:

(1)
Electric capacity is shown as net generation.

(2)
The Curtis Palmer facility was repowered in 1986.

(3)
Steam is sold to Schering under the PPA.

(4)
Gas is purchased from a local gas distribution company and Sempra Energy Trading Corporation.

(5)
Maximum capacity utilizing 100% coal for fuel supply.

(6)
Enhancements to the Roxboro facility and to one of the two units at Southport facility were completed in December 2009. Enhancements to the second unit were completed in November 2010. The Roxboro and Southport facilities originally commenced operations in 1987.

(7)
Approximately 25-30% of the Southport and 20-24% of the Roxboro facilities' fuel requirements are satisfied with coal, with the balance from tire-derived fuel and wood waste. The anticipated coal requirements for each facility are sourced with regional coal suppliers.

AAARP = Anhydrous ammonia absorption refrigeration plant
HRSG = Heat recovery steam generator
CHP = Combined Heat and Power

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Power Purchase Agreements

Canada

Ontario

        The Ontario Electricity Financial Corporation (OEFC) is the sole purchaser of power from the Partnership's five Ontario power plants. The power is purchased under long-term Power Purchase Agreements (PPAs). The earliest expiry date of these agreements is at the Nipigon plant where the initial term of the PPA expires in 2012 and the longest expiry date is at the Calstock plant where the PPA expires in 2020. See "Power Plant Summary". The Partnership reached an agreement with the OEFC to amend the Tunis PPA effective January 16, 2010 that allows the Partnership to flow-through natural gas and transportation costs in excess of benchmark amounts to OEFC and extends OEFC the right to curtail the plant during summer off-peak periods through the remaining term of the PPA in 2014.

Williams Lake

        The Williams Lake power plant sells power to the British Columbia Hydro and Power Authority (BC Hydro) under a 25-year PPA with the initial term expiring in 2018. BC Hydro has an option to extend the agreement by up to 10 years, on the basis of two five-year term extensions.

        The Williams Lake Electricity Purchase Agreement (EPA) contains two pricing tranches: a firm energy tranche, representing approximately 82% of total energy produced; and a surplus energy tranche, representing approximately 18% of total energy produced. The firm energy tranche price consists of a fixed energy component, an operations and maintenance component (adjusted annually for average weekly earnings in British Columbia), and a reimbursable cost component. The surplus energy tranche price is adjusted annually for changes in the Dow Jones California Oregon Border index. The year end surplus energy tranche price would have been set at $30/MWh for 2010, compared to $58/MWh for 2009. However the Partnership sold the surplus energy to a third party at a higher price. The surplus energy price for 2011 was set through negotiations with BC Hydro and is attractive.

Mamquam

        The Mamquam hydroelectric facility sells all of its electricity generated to BC Hydro under a long-term contract (Mamquam EPA) which will expire in October 2027. BC Hydro has an option, exercisable in 2021 and every five years thereafter, to either purchase the Mamquam facility or extend the Mamquam EPA.

        Energy rates payable under the Mamquam EPA consist of a fixed energy component, an operations and maintenance component (adjusted annually for inflation), and a reimbursable cost component which covers costs such as property taxes, water and land use fees as well as comprehensive liability insurance costs.

Moresby Lake

        The Moresby Lake hydroelectric facility sells substantially all its electricity to BC Hydro under a long-term contract (Moresby Lake PPA) which will expire in 2022. The balance, approximately 1% of its power generation, is sold to NAV Canada and the Department of Fisheries and Oceans (Canada) under long-term PPAs.

        The energy rate payable by BC Hydro under the Moresby Lake PPA consists of a fixed energy component adjusted annually for inflation.

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United States

Frederickson

        The Partnership's portion (50.15% or approximately 125 MW) of the Frederickson facility's base 249 MW generating capacity has been sold under PPAs to three Washington State Public Utility Districts (PUDs) for a term of 20 years ending in 2022. Under the PPAs, the Partnership provides generating capacity and associated energy to each PUD, and the PUDs pay the Partnership a capacity charge, a fixed operations and maintenance charge, a variable operations and maintenance charge and a fuel charge. The PUDs must supply their proportionate share of natural gas to the Partnership at Huntingdon, British Columbia. The Partnership is responsible for contracting firm transportation for natural gas from Huntingdon to the Frederickson facility. The Partnership is responsible for any fixed and variable cost increases above those recoverable under the PPAs, other than costs that result from the effects of material changes to environmental and tax laws.

Manchief

        The Manchief power plant operates under an Energy Supply Arrangement (ESA) with the Public Service Company of Colorado (PSCo) that expires in 2022 pursuant to a 10-year extension agreed to in 2006. PSCo is an electricity and natural gas distribution company that primarily serves northern Colorado. Under the ESA, PSCo purchases: (i) the electricity capacity consisting of 301.8 MW of net generating capacity per hour, or the actual net generating capacity that is available in any given hour, whichever is less; and (ii) the electrical energy which is actually dispatched by PSCo and associated with such capacity, and Manchief is paid capacity and energy payments. Capacity payments are typically stable and are made on a monthly basis, regardless of whether the plant is actually dispatched by PSCo. Energy payments are also made on a monthly basis and are comprised of tolling fees, start-up fees, heat rate adjustment payments (payable either to or by Manchief) and natural gas transportation charges. Starting in May 2012, the capacity payments will be reduced by approximately 15% under the tolling arrangement.

        Manchief obtains operations and maintenance services for its generating facility from Colorado Energy Management, LLC pursuant to the terms of a plant operating and maintenance agreement.

        The Partnership and PSCo have also signed an Option Agreement under which PSCo has the right, during the latter part of the ESA extension term, to acquire the Manchief power plant. If PSCo exercises the purchase option, the Partnership would receive a fixed purchase price, as specified in the Option Agreement, which management believes will maintain the economic value of the 10-year ESA extension and compensate the Partnership for the power plant's expected residual value.

Greeley

        The Greeley facility provides all of its electrical output to PSCo under an on-system PPA which expires in August 2013. PSCo pays the Greeley facility a monthly capacity payment and energy payment pursuant to the PPA. The Partnership entered into a three-year forward natural gas swap contract expiring in October 2011 that covers most of the anticipated supply requirements for the Greeley facility during this period. Extension of the forward swap to cover the expiry of the PPA is being evaluated by management.

        Under a development agreement between Ventures and KN/Thermo LLC, KN/Thermo LLC is currently entitled to up to 33.5% of the Pre-Tax Cash Flow from the Greeley facility. Pre-Tax Cash Flow is defined in the development agreement to include the net proceeds realized by the Partnership from the sale of the Greeley facility under certain circumstances, and cash proceeds received from operation of the Greeley facility (including from sales of electric power and hot water), as reduced by the reasonable operating costs of the facility.

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California Facilities

        The Partnership's California facilities are comprised of three facilities located on U.S. naval bases (the Naval Facilities) and the Oxnard facility.

        The Naval facilities are comprised of Naval Station, North Island and Naval Training Center. Except for the 4 MW steam turbine at the North Island facility, each of the Naval Facilities provides all of its electrical output to San Diego Gas and Electric Company (SDG&E) under the terms of the Long Run Standard Offer No. 4 for Power Purchase and Interconnection agreements from Qualifying Facilities, each of which expire in 2019. SDG&E is an electricity and natural gas distribution company primarily serving the San Diego area. Each of the Naval Facilities is required to operate throughout the term of the applicable PPA as a Qualifying Facility (QF) in accordance with the cogeneration facility requirements established by the Federal Energy Regulatory Commission (FERC).

        In 2009, the Partnership completed an upgrade to its gas turbine at the North Island facility in southern California from a GE LM5000 to a GE LM6000 unit for an approximate cost of US$17.0 million. The repowering project was completed in time for the summer peak demand season in Southern California. The project improved the operating efficiency of the facility reducing the gas turbine gross heat rate by approximately 1,127 Btu/kWh. The replaced LM5000 unit will be available as a spare gas turbine for the Partnership's other LM5000 turbines. The energy produced by the 4 MW steam turbine at the North Island facility is sold to the U.S. Navy (the Navy) at a discount to SDG&E's retail rates. The energy produced by the 2.5 MW steam turbine at the Naval Training Center is sold to SDG&E under a Standard Offer No. 1 for Power Purchase and Interconnection from Qualifying Facilities (SO1). The energy rates under the SO1 are the SDG&E short run avoided cost (SRAC) rates. Capacity payments are paid on an as-available basis under rates that are reviewed by the California Public Utility Commission (CPUC) periodically.

        The Navy has the right to terminate the Naval Facility Negotiated Utility Service Contracts (NUSCs) for convenience on one year's notice. Termination costs incurred under the PPA would be reimbursed under the NUSC in the event of termination for convenience. See "Thermal Supply Agreements".

        The Oxnard facility provides all of its natural gas turbine electrical output to Southern California Edison Company (SCE) under a contract (Oxnard PPA) that expires in 2020. SCE is an electricity and natural gas distribution company primarily serving areas of southern California outside Los Angeles and San Diego. The Oxnard facility is required to operate throughout the term of the Oxnard PPA meeting QF efficiency standards in accordance with the cogeneration facility requirements established by the FERC. The Oxnard facility is qualified as both a QF and an Exempt Wholesale Generator (EWG).

        In May 2010, the Partnership completed the replacement of the existing GE LM5000 natural gas turbine with a more efficient and reliable GE LM6000 at Oxnard at a cost of US$19.2 million. The final capital cost could potentially be lower if the sale of the used General Electric LM5000 turbine is successful. The repowering project was completed in time for the summer peak demand season in Southern California. While the project improved the Oxnard facility heat rate by 3%, the primary economic driver of the project is an expected reduction in forced outage costs relative to the GE LM5000.

        The price paid under the Naval Facilities' PPAs includes a capacity payment and an energy payment based on SDG&E's SRAC. The price paid under the Oxnard PPA includes a capacity payment and an energy payment based on SCE's SRAC. Capacity payments are based on achieving availability performance targets. These performance requirements require that forced outage rates for the facility are to be less than 20% during specified on-peak hours during the summer peak demand months. An additional performance bonus is applied when on-peak forced outage rates are less than 15%. Each of

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the Naval Facilities and the Oxnard facility has historically achieved its firm capacity revenue and near maximization of capacity bonus revenues.

        On September 20, 2007, the CPUC accepted an alternative decision regarding revisions to the SRAC formulae that became effective August 1, 2009. The essence of the decision was to provide a 50/50 split between market and administratively determined heat rates for the calculation of the overall heat rate used in the energy price calculation; provide an escalating operating and maintenance fee adder; and use a 12-month forward-looking market heat rate rather than the historical pricing. The SRAC change impacts the steam payment component of the Naval Facilities PPAs and the Partnership is currently in discussions with the Navy regarding implications of future steam pricing. See "Regulation—California".

        SRAC energy prices are published monthly in accordance with the above mentioned decision. As such, this pricing provision recovers the month-to-month natural gas costs related to electricity production and substantially passes through the fuel cost to SDG&E and SCE in the variable energy charge. Time of use factors are applied to the SRAC energy rate to value the electricity delivered during on-peak hours relative to electricity delivered during off-peak hours. The Oxnard facility typically operates during on-peak hours in order to take advantage of higher electricity prices provided from on-peak time of use rates. Changes in natural gas prices have a nominal impact on the Oxnard facility's operating margin.

Curtis Palmer

        The Curtis Palmer hydroelectric facility sells all power generated to Niagara Mohawk Power Corporation (Niagara) under a long-term contract (Curtis Palmer PPA). The Curtis Palmer PPA ends after the earlier of 2027 and the delivery to Niagara of a cumulative 10,000 GWh of electricity.

        The Curtis Palmer PPA sets out 11 different prices for electricity sold to Niagara, with the applicable price to be paid at any given time being dependent upon the cumulative GWh of electricity which have been delivered to Niagara. In December 2008, the pricing increased by 18% as the plant moved into the sixth pricing block. Over the remaining term of the PPA, the price increases by US$10/MWh with each additional 1,000 GWh of electricity delivered. The plant requires approximately three years to move through each 1,000 GWh block, depending upon river flow.

        Under certain circumstances, Niagara has the ability to relocate, rearrange, retire or abandon its transmission system which would potentially give rise to material future capital cost outlays by Curtis Palmer to maintain its interconnection.

Morris

        The Morris facility sells electrical energy to Equistar Chemicals, LP (Equistar), a wholly-owned subsidiary of LyondellBasell AF S.C.A. (LyondellBasell), under an ESA that expires in 2023. Pursuant to the Morris ESA, Equistar pays a tiered energy rate based on the amount of energy consumed to a maximum of 77 MW. Equistar also pays capacity fees, comprised of both a non-escalating fixed fee that expires in 2013 and a variable fee that escalates with materials and labour indices and expires in 2023. The non-escalating capacity payment is fixed at US$8.3 million per year. In addition, the Morris facility earns energy payments based on electricity and steam delivered that is adjusted monthly for natural gas prices. Based on the energy payment formula, there is a small portion of energy costs that are not recovered through the energy payments, and this non-recoverable amount fluctuates with the price of natural gas. Most of this natural gas price exposure has been hedged through 2011. Equistar has a right to purchase the Morris facility at fair market value at the end of 2013, 2018 and 2023. The Morris facility is certified as a QF.

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        Subordinate to the needs of Equistar, the Morris facility has a PPA with Exelon Generation Company, LLC (Exelon) covering 100 MW of electrical capacity that expires in April 2011. Exelon pays a capacity charge that varies based on the time of year together with an energy charge based on amount of energy dispatched. The annual capacity revenue earned under the PPA with Exelon has averaged just over US$6 million per year, including bonus payments for peak availability that exceeds 98%.

        Excess capacity and energy above the needs of Equistar and Exelon can be sold into the Pennsylvania, New Jersey, and Maryland (PJM) market. The 100 MW of electrical capacity that is currently serving the Exelon PPA has been sold through the PJM market from May 2011 to April 2014 at auction prices that are lower than the Exelon contract resulting in slightly lower capacity revenue.

        On January 6, 2009, Equistar, along with LyondellBasell's other North American operating entities, filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Since that date, Equistar made all post-petition payments required under the ESA. On April 23, 2010 the plan of reorganization for LyondellBasell's U.S. subsidiaries, including Equistar, under Chapter 11 of the U.S. Bankruptcy Code was approved. Pursuant to the plan of reorganization, Equistar assumed the Morris ESA, and as a result, the Partnership received a US$12.4 million payment for pre-petition services under the ESA along with interest.

Kenilworth

        The Kenilworth facility sells electrical energy to Schering-Plough Corporation (Schering), a subsidiary of Merck & Co., Inc., under an amended and extended ESA that expires in July 2012. Pursuant to the Kenilworth ESA, Schering pays an energy rate that escalates annually. The Kenilworth ESA imposes a minimum take or pay obligation on Schering of 125,000 MWh per year. Load growth at Schering's facility over the years has caused certain seasonal loads to match more closely with the capacity of the Kenilworth facility. Excess generation above the Schering loads are sold to Public Service Enterprise Group Incorporated under a contract entered into in 2009.

North Carolina Facilities

        The Roxboro and Southport facilities provide all of their electrical output under PPAs to Carolina Power & Light Company (CP&L), which is a regulated utility servicing North Carolina and South Carolina, and is a subsidiary of Progress Energy Inc. (Progress). The electric output from the facilities is sold to Progress pursuant to PPAs which expired on December 31, 2009, but which have been extended pending resolution of arbitration before the North Carolina Utilities Commission (NCUC). The Partnership filed for arbitration with the NCUC and is seeking long term PPAs with pricing terms consistent with Progress's actual avoided costs. The NCUC has ordered that Progress continue to pay for the output of the North Carolina facilities pursuant to the terms of the PPAs that expired December 31, 2009 until the arbitration is finalized. On this interim basis, the price paid includes a capacity payment, an energy payment that reflects the price paid for coal, and a cycling charge. If this pricing does not result in a dispatch order for the facility, the Partnership has the right, but not the obligation, to bid an alternate price based upon its own pricing strategies to obtain a dispatch order. See "Business Risks—Power Purchase Contract Expiry Risk" in the MD&A. On January 27, 2011, the NCUC issued an Order on Arbitration which provided direction on four fundamental issues: (i) that a legally enforceable obligation was created in July 2008 and that, accordingly, it is appropriate to use Progress' June 2008 fuel forecasts as the basis for determining the avoided cost fixed energy rates for the new PPAs; (ii) that the facilities are entitled to receive full capacity payments in respect of the full term of the PPAs; (iii) that Progress' avoided capacity costs should be calculated based on the average unit cost to construct four combustion turbines at a single site; and (iv) that a 10-year term would be fair and appropriate for the new PPAs with the term starting from the time when the new PPAs are signed. The Order on Arbitration did not set a deadline for the completion of negotiations but requires

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the Partnership and Progress to report on the status of negotiations within 30 days, if no agreement is reached sooner. On February 25, 2011, a joint report on the status of negotiations was filed in which the parties state that they have reached agreement on the majority of key commercial terms and will begin drafting final PPAs, with the goal of having an April 1, 2011 effective date.

        The North Carolina facilities burn a mix of wood waste, tire-derived fuel and coal. Both facilities have undergone substantial capital improvements designed to significantly reduce their NOx and SO2 emissions. These changes will additionally reduce the facilities' fuel costs via increased use of wood waste and tire-derived fuel accommodated via modified equipment design. In the fourth quarter of 2010, the Partnership completed the final phase of the enhancement project designed to reduce environmental emissions and improve the economic performance of the Southport and Roxboro facilities by increasing the use of tire-derived fuel and wood waste in the fuel mix. Project costs incurred to December 31, 2010 were US$82 million with an additional US$5 million to be spent in 2011 on access roads and final testing. The Partnership had anticipated a reduction in the capacity of Southport and Roxboro to approximately 88 megawatts (MW) and 46 MW respectively as a result of the increased use of wood waste and tire-derived fuel. The reduction in the capacity levels as a result of the change to a greater level of wood waste and tire-derived fuel in the fuel mix may be greater than previously expected. Recent testing indicates the plants may only be able to achieve capacities of 84-87 MW at Southport and 42-44 MW at Roxboro based on the targeted fuel mix. Management is assessing whether a shortfall in capacity can be practically resolved.

        As QFs under the FERC rules, both Roxboro and Southport can sell to CP&L under a special avoided cost rate determined every two years, and can supplement this revenue stream with sales of Renewable Energy Credits (REC) to satisfy North Carolina's Renewable Energy Portfolio Standard. As part of the capital investment, both plants dramatically increased their wood fuel percentage and thus achieved certification as REC providers. To reclaim its QF status, Roxboro increased its minimum non-coal fuel percentage to 75%, thus qualifying as a Small Power Producer on January 1, 2010. The Southport facility has been QF certified since initial operations in 1987.


Thermal Supply Agreements

        The Greeley facility sells hot water to the University of Northern Colorado (UNC) pursuant to a Thermal Supply Agreement (TSA) which expires in August 2013. Under the Greeley TSA, the Greeley facility is obligated to deliver for sale to UNC only such heat energy as is generated during the production of electrical capacity and energy for sale to PSCo. The charge per million Btu of thermal energy is calculated in a manner that gives UNC a discount when compared to UNC avoided natural gas-fired boiler costs.

        The Naval Facilities sell steam to the Navy pursuant to NUSCs, each of which expires in February 2018. The Naval Facility NUSCs give the Navy a right to purchase electrical energy from the Naval Facilities at prices comparable to those under the Naval Facility PPAs. Under the Naval Facility NUSCs, the Navy has an obligation to consume enough thermal energy for the Naval Facilities to maintain their QF status. The Navy has the right to terminate the SPAs for convenience on one year's notice. The Navy is obligated to pay a termination payment if it breaches an agreement or causes any loss of a Naval Facility's QF status.

        The contracted steam for the Naval Facilities is based on a take or pay formula using a specified volume at each facility. Additional steam can be taken above these specified volumes and such steam is priced at avoided package boiler costs. The monthly price payable by the Navy for steam under the Naval Facility NUSCs includes: (i) a steam commodity charge; (ii) fixed service charge for plant capital and operations and maintenance avoidance; and (iii) water cost pass-through provisions, a feed water charge and a credit for condensate return.

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        Steam pricing is linked to the cost of natural gas and SDG&E's SRAC by an energy sharing formula. This formula provides the Naval Facilities with reduced price volatility as the SRAC price of electricity primarily increases or decreases as a result of changes to the price of natural gas. Changes in natural gas prices have a nominal impact on the Naval Facilities' cash provided by operating activities. On September 20, 2007, the CPUC accepted an alternative decision regarding revisions to the SRAC formulae that became effective on August 1, 2009. See "Regulation—California".

        The Oxnard facility supplies steam to its anhydrous ammonia absorption refrigeration plant, which then provides refrigeration services to Boskovich Farms at no charge; thereby maintaining the Oxnard facility's QF status.

        The Morris facility sells steam to Equistar to a maximum of 720 million lbs/hr under the Morris ESA through 2023. Ten year average usage is approximately 320 million lbs/hr. The Morris ESA charge for steam is calculated on the basis of a tiered pricing schedule ranging from US$2.60/mlbs of steam to US$3.18/mlbs of steam depending on quantity of average monthly steam demand. The agreement provides for the option to renegotiate pricing if steam demand falls outside a set range for a stipulated period of time. See "Power Purchase Agreements—United States—Morris" in this AIF, and "Business Risks—Qualifying Facility Status Risk" in the MD&A.

        The Kenilworth facility sells steam to Schering under an amended and extended Kenilworth ESA that expires in July 2012. The Kenilworth ESA provides for a contract minimum of 160,000 million Btu per year. The average annual heat content of steam sales directly from the Kenilworth facility under the terms of the Kenilworth ESA has been higher (740,000 million Btu per year average) than the contract minimum. The Kenilworth ESA charge per million Btu of steam is calculated as a function of the delivered cost of fuel to Schering's auxiliary boilers. Schering is able to request long term purchase strategies to minimize the monthly volatility of natural gas prices.

        The Partnership filed for market-based rate authority with the FERC, which was granted effective January 1, 2008, in endeavoring to ensure that the Roxboro facility would have the requisite authority in place to sell power under the Roxboro PPA in the event the facility does not have a steam host. Currently, the facility does not have a steam host and the Partnership does not expect one to emerge. The Southport facility sells steam pursuant to a Steam Purchase Contract which expires in December 2014 to Archer Daniels Midland Company (ADM). ADM has committed to purchase a minimum quantity of steam equivalent to 5% of the total energy output of the Southport facility. The Southport facility is required to make all reasonable efforts to provide a continuous supply of steam. However, the Southport facility is not responsible for any loss or damage resulting from a failure to maintain continuous steam service. Southport operates the boilers to provide steam continuously, even when the plant is not dispatched.


Fuel Purchase Agreements

        The largest of the Partnership's expenses is the cost of fuel used in the generation of electricity. Fuel costs include the natural gas commodity price, natural gas transportation charges, waste heat optimization costs and wood waste costs at the Calstock and Williams Lake plants and wood waste, tire-derived and coal fuel prices and transportation costs at the Roxboro and Southport facilities. Wood waste costs include the cost of wood waste, the transportation of wood waste, fuel and management costs and the disposal of wood ash. Although wood waste and the related transportation services have been purchased under contract for the majority of the fuel requirements at the Calstock and Williams Lake facilities, the suppliers have no obligation to provide in the event they scale back or shut down operations.

        The Partnership purchases fuel gas and/or waste heat for each of the Ontario power plants except Tunis, under long-term natural gas and waste heat supply agreements. The Partnership reached an agreement with the OEFC to amend the Tunis PPA effective January 16, 2010 that allows the

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Partnership to flow-through natural gas and transportation costs in excess of benchmark amounts to OEFC and extends OEFC the right to curtail the plant during summer off-peak periods through the remaining term of the PPA in 2014. Firm capacity for the transportation of fuel gas to the Ontario power plants has been contracted for on the TransCanada natural gas transmission system under long-term transportation agreements, the earliest of which expires in 2011. See "Business Risks—Energy Supply Risk" in the MD&A.

        In late 2008, the Partnership completed a new supply agreement with a nearby wood waste landfill site for Calstock. The landfill site is estimated by management to have equivalent to one million green metric tons of supply, which is equal to three years of supply for the plant. Pursuant to a Certificate of Approval (CoA) from the Ministry of Environment, Calstock successfully completed a rail ties test burn in November 2009. The Partnership has applied for a permanent CoA amendment from the Ministry of Environment. If approved, the rail ties could provide up to 20% of the Calstock facility's fuel requirement.

        Wood waste supply to the Williams Lake facility was sufficient in 2010. Traditional suppliers returned to near normal production levels with the exception of one supplier who continues to idle one of their sawmills. The Partnership has identified other sources of supply to replace volume lost from the curtailed sawmill. These sources are more expensive; however, approximately 82% of the fuel cost is borne by BC Hydro under the PPA. The facility is well positioned to withstand potential fuel shortages largely due to an agreement with Pioneer Biomass Inc. to supply processed forest based residuals, on an as needed basis, to the Williams Lake facility. Fuel inventory levels were reduced significantly in 2010 to bring back to normal operating levels. The expanded wood waste storage capacity continues to provide flexibility in managing available lower cost wood waste supplies. At December 31, 2010, the plant had sufficient wood waste inventory for the plant to produce its maximum output of 66 megawatts (MW) for 35 days at full output.

        Natural gas supply purchased for the Greeley facility is financially fixed under an agreement with Shell Energy North America and CP Energy Marketing (US) Inc. which expires in October 2011. Natural gas for the Naval Facilities and Oxnard is purchased through natural gas contracts with RBS Sempra Energy Trading Corporation (Sempra) at monthly index prices similar to those used in the utility SRAC calculations. Kenilworth natural gas is also purchased from Sempra with that price used directly in the steam pricing under the ESA. The Morris facility obtains the majority of its required natural gas through a Purchase and Sale Agreement with DCP Midstream Marketing LP and Tenaska Power Services Co. (Tenaska) which expires in 2016 at a price indexed to the Chicago City Gate market. Under the agreement, Tenaska also provides power market trading services through a year-to-year agreement that may be cancelled on 60 days notice. Additionally, the Morris facility contracts gas storage facility as a seasonal hedge and to maximize operational flexibility.

        Approximately 25-30% of the Southport and 20-24% of the Roxboro facilities' fuel requirements are satisfied with coal, with the balance from tire-derived fuel and waste wood. The anticipated coal requirements for 2011 for each facility are sourced with regional coal suppliers. Tire-derived fuel and waste wood are sourced from multiple local suppliers. Tire-derived fuel is procured under fixed-price contracts, and waste wood is procured at fixed prices indexed to the transport distance from the facility and subject to a fuel surcharge.


Partnership Waste Heat Agreements

        Pursuant to long-term waste heat agreements, TransCanada provides the Ontario power plants with all waste heat generated by the natural gas turbine compressors located at the compressor stations adjacent to the Ontario power plants on an as available basis. Each agreement continues in effect for as long as the Partnership delivers electrical energy from the particular plant. The waste heat agreements provide that TransCanada will be obligated to supply waste heat to the Ontario power

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plants only when such waste heat is available from the compressor stations. In the event waste heat output is reduced at a compressor station as a result of reduced natural gas turbine output arising from any cause, TransCanada's obligation to deliver waste heat is reduced accordingly. See "Business Risks—Energy Supply Risk" in the MD&A.

        In 2003, the Partnership entered into an agreement with TransCanada to optimize the waste heat availability at certain of the Partnership's Ontario plants. Under the agreement, the Partnership pays for incremental natural gas used in the compressor station turbines to optimize the quantities of waste heat which can be available to the Partnership's adjacent power plant. Any incremental maintenance or repair costs as a result of the increased use of TransCanada's turbines are also charged to the Partnership.


PERC Management Arrangements

        Pursuant to the PERC Management Agreement, the Partnership, through Ventures, provides management and administrative services to PERH and its subsidiaries and, if and to the extent requested by PERC, provides certain administrative services to PERC. The initial term of the PERC Management Agreement expires in 2025. In consideration for providing the management and administrative services, the Partnership receives a base annual management fee.

        Concurrently with the PERH recapitalization in August 2009, certain changes were made to the PERC Management Agreement. The changes include: (i) PERH has assumed responsibility for certain management functions, (ii) the parties agreed that PERH can terminate the management agreement for a specified price, declining over time, if the Partnership agrees to sell its interest in PERH, and (iii) the allocation agreement among the Partnership, PERC and certain other parties, together with the rights of first offer in respect of certain projects of the Partnership granted to PERC and to PERH under the PERC Management Agreement and the allocation agreement, have been terminated. See "General Development of the Business—Three Year History".

        PERC, through PERH and its subsidiaries, competes with the Partnership. The PERC Management Agreement does not prohibit the Partnership or its affiliates from competing with PERC or PERH or from acquiring, investing in, or providing administrative or managerial services to a competitor of PERC. Pursuant to the PERC Management Agreement, PERC, PERH and its subsidiaries acknowledge and agree that the Partnership and its affiliates may engage in activities similar to and competitive with those of PERC, PERH and its subsidiaries.


Employees of the Partnership

        Neither the Partnership nor the General Partner has any employees. All day-to-day operations at the Canadian and U.S. power generation facilities are undertaken by employees of Capital Power with the exception of the Manchief facility. Operations and maintenance services for the Manchief facility are supplied by a contracted service provider, Colorado Energy Management, LLC.

        All senior officers of the Partnership are employed by, and obtain all of their compensation from, Capital Power, and compensation for their services to the Partnership is paid by Capital Power. The directors and officers of the Partnership who are officers or employees of Capital Power do not receive any compensation directly from the Partnership for such services. See "Compensation Discussion and Analysis".

        The Canadian operations have approximately 23 non-unionized employees at North Bay, Mamquam and Moresby Lake. The facility operations at Nipigon, Kapuskasing, Tunis and Calstock unionized in the spring of 2006. The Power Workers' Union of Ontario is the certified bargaining agent for approximately 46 employees at these facilities and has a collective agreement with Capital Power which expires in December 2013. At the Williams Lake facility, there are approximately 23 unionized

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employees whose United Steel Workers local has a collective agreement with Capital Power which expires in December 2011. The United States operations have approximately 167 non-unionized employees.


Expansion, Enhancement and Acquisition Opportunities

        Where opportunities arise, the Partnership will seek to grow its asset base by expanding capacity and implementing enhancements at existing plants and by pursuing acquisition or development opportunities that meet the Partnership's investment criteria and are accretive to cash flows. These criteria include generation assets that have relatively stable and predictable cash flows; risk profiles similar to the assets already owned by the Partnership; and with predictable capital expenditures and long operating lives.

        The Ontario PPAs contain provisions that, under certain circumstances and subject to the consent of OEFC, allow for the sale of additional electricity to the extent that the plants subject to the agreements are physically expanded. Expansions could be achieved in a number of ways; however, at present there is no agreement with OEFC to expand the Ontario plants.


RISK FACTORS

        The Partnership has direct ownership interests in a portfolio of 20 power generation assets that operate using six different fuel types in two countries, and also a 14.3% equity ownership interest in another organization that owns 5 plants, and is therefore subject to a number of business and operational risks.

        A detailed discussion of risk factors is included in the section on "Business Risks" in the Partnership's MD&A dated March 2, 2011 and filed on SEDAR.


REGULATION

        Set forth below is an overview of the principal electrical power regulatory regimes to which the Partnership's operations are subject. Environmental regulations affecting the Partnership's operations are discussed under "Environmental Regulation".

        The Partnership's operations are subject to extensive regulation by governmental agencies. In addition to environmental regulation, the Partnership's facilities and operations are subject to laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the development and construction of generation facilities, the ownership and operations of generation facilities, access to transmission, and the geographical location, zoning, land use and operation of a facility.


Ontario

        The OEFC is one of five corporations established by the Electricity Act, 1998. OEFC is the purchaser of 100% of the power produced by the Partnership's operations in Ontario. This relationship has remained stable despite numerous regulatory and policy changes over the intervening years. The formation of the Ontario Power Authority (OPA) in 2004, while having no impact on the existing contracts, is helpful in that it will provide a creditworthy counterparty with whom to negotiate replacement PPAs as the existing agreements expire.

        On September 20, 2010, the Ontario Minister of Energy announced a revised process regarding the development of the Integrated Power System Plan (IPSP). On November 23, 2010, the Ontario Ministry of Energy issued its "Long-Term Energy Plan" (LTEP) and a proposed new supply mix directive. Subject to a 45 day posting of the proposed supply mix directive on the Environmental Registry, the OPA will prepare a detailed IPSP, hold consultations, and submit a revised IPSP to the Ontario Energy

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Board (OEB) by mid 2011 with review by the OEB to take place between 2011 and 2012. Once reviewed and approved by the OEB, the IPSP will be updated every three years as required by regulation.

        On October 7, 2010, the Ontario government announced that the 900 MW Oakville Generating Station selected by the OPA for the southwest Greater Toronto Area was no longer required and would be cancelled. The LTEP issued on November 23, 2010 referenced this cancellation but noted that natural gas would continue to play a strategic role in Ontario's supply mix by complementing intermittent supply from renewable energy projects, meeting local and system requirements, and ensuring that adequate capacity is available as nuclear plants are modernized, and that the OPA will continue to plan on natural gas usage for those strategic purposes. The LTEP specifically noted that the procurement of a natural gas-fired plant in the Kitchener-Waterloo-Cambridge area, as was originally envisaged in the original IPSP submitted to the OEB in 2007, is still necessary to ensure adequate regional electricity supply.


British Columbia

        BC Hydro is the principal purchaser and distributor of electricity in the Province of British Columbia. BC Hydro is owned by the Province of British Columbia and is regulated by the British Columbia Utilities Commission (BCUC). The British Columbia Government Energy Plan (BC Energy Plan) and direction to BC Hydro have the effect of making hydroelectric, wind and wood waste electricity generation more favourable than natural gas and coal fired electricity generation.

        On August 27, 2009, the Government of British Columbia affirmed that development of clean and renewable energy sources will continue to be aggressively promoted and pursued in conjunction with energy self-sufficiency both to support achievement of British Columbia's climate action plan goals and to position British Columbia as a "clean energy powerhouse" as per the BC Energy Plan.

        On April 28, 2010, the Government of British Columbia introduced a new Clean Energy Act that aims to aggressively accelerate and expand development of clean and renewable energy sources within the Province of British Columbia to achieve energy self-sufficiency, job creation and greenhouse gas reduction objectives. The Clean Energy Act also re-integrates British Columbia Transmission Corporation (BCTC) into BC Hydro and provides a new role for BC Hydro to actively market and expand sales of BC clean power in export markets. The Clean Energy Act received Royal Assent on June 3, 2010, and BCTC was re-integrated into BC Hydro effective July 5, 2010.

        The Clean Energy Act requires BC Hydro to submit an Integrated Resource Plan (IRP) by November 2011. The long-term electricity planning framework and expanded opportunities for contracted power development for both BC domestic use and BC Hydro export purposes established through the Clean Energy Act, and addressed through the forthcoming IRP, could provide opportunities for the Partnership. The Clean Energy Act would also streamline regulatory approval processes for future projects qualifying for contracts with BC Hydro.


U.S. Energy Industry Regulatory Matters

Federal Energy Regulatory Commission (FERC) Jurisdiction

        Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or transmission of electric energy in interstate commerce is a public utility subject to FERC's jurisdiction. FERC has extensive ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy under the Federal Power Act (FPA) and with respect to certain interstate sales, transportation and storage of natural gas under the U.S. Natural Gas Act of 1938 (NGA), as amended and the U.S. Natural Gas Policy Act of 1978 (NGPA), as amended. FERC also maintains certain reporting requirements for public utilities and regulates, among other things, the

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disposition and acquisition of certain assets and securities, the holding of certain interlocking directorate positions, and the issuance of securities by public utilities.

Transmission Service

        Issued in 1996, FERC Order No. 888 mandated the unbundling of utilities' transmission and generation services and required such utilities to offer eligible entities open access to utility transmission facilities on a basis comparable to the utilities' own use of the facilities. FERC Order No. 888 required public utility transmission owners to file open access transmission tariffs containing the terms and conditions under which they would offer transmission service, enabling independent generators and marketers to schedule and reserve capacity on those transmission facilities. In 2007, FERC Order No. 890 made a number of changes to open access implementation, including requiring an open, transparent and coordinated transmission planning process on both a local and regional basis.

        In 1999, FERC issued Order No. 2000, which set out standards for Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs). These organizations are operated by an entity that is independent of market participants, and planning, operations, and transmission services are performed on a regional instead of utility specific basis. In addition, most ISOs and RTOs administer liquid day-ahead and real-time spot markets. Examples are PJM Interconnection, ISO New England, New York ISO, Midwest Independent Transmission System Operator and California ISO. In 2008, FERC Order No. 719 made incremental reforms to such markets, including requiring scarcity pricing to encourage demand response and other new resources.

Market-Based Rate Authority

        Under the FPA and FERC's regulations (subject to certain exceptions for entities such as municipal utilities that are not public utilities under the FPA), an entity seeking to make wholesale sales of power at market-based or cost-based rates must obtain authorization from FERC. FERC grants market-based rate authorization if it finds that the seller and its affiliates lack market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and the seller and its affiliates comply with certain affiliate restrictions. All of the Partnership's affiliates that own power plants in the U.S. (except for those power plants that are QFs, as well as the Partnership's power marketer affiliates, are currently authorized by FERC to make wholesale sales of power at market-based rates. This authorization is subject to revocation by FERC if such companies fail to continue to satisfy FERC's current or future criteria for market-based rate authority or to modification if FERC restricts the ability of wholesale sellers of power to make sales at market-based rates.

Mergers and Acquisitions

        FERC has FPA jurisdiction over certain sales, mergers, consolidations and acquisitions of public utility assets or securities, and over certain mergers and acquisitions involving holding companies and transmitting utilities or electric utility companies. In reviewing such matters, FERC reviews the effect of the transaction on competition, rates and regulation and ensures that there is no unlawful cross subsidization of affiliates by entities with captive customers.

Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs)

        ISOs grew out of Orders Nos. 888/889 where the Commission suggested the concept of an ISO as one way for existing tight power pools to satisfy the requirement of providing non-discriminatory access to transmission. Subsequently, in Order No. 2000, the Commission encouraged the voluntary formation of RTOs to administer the transmission grid on a regional basis throughout North America. With the exception of the southeast and northwest, most wholesale power markets in the lower 48 states of the

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United States are controlled by RTOs operating under FERC jurisdiction. The organized markets under each of these RTOs have developed differently, each with their own variation of markets. The northeast region (PJM, NYISO and ISO-NE) is considered the more developed of the RTOs but each region has its own uniqueness of history, market participants, resources and state involvement. Market rules continue to evolve. The non-organized market regions of the northwest and southeast typically represent the old model of vertically integrated utilities and opportunities there are limited to bilateral contracts.

Reliability Standards

        Pursuant to the U.S. Energy Policy Act of 2005, FERC finalized in February 2006 new rules regarding the certification of an Electric Reliability Organization and the procedures for the establishment, approval and enforcement of mandatory electric reliability standards. In July 2006, FERC certified North American Electric Reliability Corporation (NERC) as the Electric Reliability Organization to establish and enforce reliability standards applicable to all owners, operators and users of the bulk power system. NERC relies on regional reliability entities to enforce FERC and NERC standards with bulk power system owners, operators, and users through approved delegation agreements. Such regional entities are responsible for monitoring compliance of the registered entities within their regional boundaries, assuring mitigation of all violations of approved reliability standards and assessing penalties and sanctions for failure to comply.

FERC Enforcement Authority

        FERC has the authority to enforce the statutes it is responsible for implementing and the regulations it issues under those statutes. The U.S. Energy Policy Act of 2005 conferred substantial enforcement authority on FERC, allowing it to impose civil penalties of up to U.S. $1 million per day per violation for violations of the NGA, NGPA and Part II of the FPA. This expanded penalty authority also applies to any entity that manipulates wholesale natural gas or electric markets by engaging in fraud or deceit in connection with jurisdictional transactions. In addition, these laws allow for the assessment of criminal fines and imprisonment for violations.

The Public Utility Regulatory Policies Act of 1978

        The Public Utility Regulatory Policies Act of 1978, as amended (PURPA) and FERC's regulations under PURPA provide certain incentives for the development of combined heat and power facilities and small power production facilities using alternative or renewable fuels, in part by establishing certain exemptions from the FPA and the U.S. Public Utility Holding Company Act of 2005 for owners of QFs.

        PURPA provides two primary benefits to QFs. First, all cogeneration facilities, geothermal and biomass small power production facilities, and small power production facilities 30 MW or smaller that are QFs are exempt from certain provisions of the FPA, the regulations of FERC thereunder and the U.S. Public Utility Holding Company Act of 2005. Second, the FERC regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs that are directly, or under certain circumstances indirectly, connected to such electric utilities at a price based on the purchasing utilities avoided cost and that such utilities sell back up power to such QFs on a non-discriminatory basis. An electric utility may be entitled to relief from these mandatory purchase and sale obligations if, in the case of the mandatory purchase obligation, the utility can show that the QF has non-discriminatory access to a market that meets certain competitive conditions and, in the case of the mandatory sale obligation, if the utility can show that that there are competing retail electric suppliers willing and able to sell and deliver electricity to the QF and there is no obligation under state law for the utility to make such power sales. The provisions for relief from the mandatory purchase and sale obligations do not affect contracts entered into or pending approval on or before August 8, 2005.

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        Under FERC's regulations, QFs are subject to FERC's rate making authority under the FPA and are required to obtain market-based rate authority in order to sell power at market-based rates, except for sales of energy or capacity: (i) made by QFs that have a generating capacity of 20 MW or less; (ii) made pursuant to a contract executed on or before March 17, 2006; or (iii) made pursuant to state-approved avoided cost rates.

        PURPA establishes certain thermal use and efficiency requirements for QFs. Loss of a steam host or changes in operations at the facility or at the steam host may result in non-compliance with such requirements. The Partnership endeavours to monitor regulatory compliance by its QF facilities in a manner that minimizes the risks of losing these facilities' QF status. If any of the QF facilities in which the Partnership has an interest were to lose its status as a qualifying cogeneration facility, that facility would no longer be entitled to the QF-related exemptions and could become subject to rate regulation under the USFPA and additional state regulation. Loss of QF status could also trigger defaults under covenants to maintain QF status in the facilities' PPAs, SPAs and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. Loss of QF status on a retroactive basis could lead to, among other things, fines and penalties, or claims by a utility customer for the refund of payments previously made. If the obligation to purchase from some or all of the Partnership's QFs is terminated, the Partnership will seek alternative purchasers for the output of such QFs or enter into negotiated rate contracts with existing counterparties once their current contracts expire. Such sales will be at prevailing market rates, which may not be as favourable as the terms of the PURPA sales arrangements under existing contracts and thus may diminish the value of the Partnership's QFs.

        In November 2007, FERC granted a limited request for waiver of FERC's QF operating and efficiency standards for the Roxboro facility due to an inability to find a replacement steam host. On January 1, 2010 Roxboro was recertified as a QF under the requirement for a Small Power Producer due to its ability to utilize renewable fuel.

Public Utility Holding Company Act of 2005

        In August 2005, the passage of U.S. Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935 and enacted the U.S. Public Utility Holding Company Act of 2005, effective February 2006, which primarily addresses FERC's access to the books and records of holding companies. Any entity that is a holding company solely with respect to QFs, exempt wholesale generators or foreign utility companies, such as the Partnership, is exempt from FERC's books and records requirements and any accounting, record-retention and reporting requirements contained in the U.S. Public Utility Holding Company Act of 2005 and FERC's regulations promulgated thereunder.


California

        The Naval Facilities in San Diego and the Oxnard facility in Oxnard sell energy to SDG&E and SCE respectively on the basis of each utility's SRAC formula.

        On September 20, 2007, the CPUC accepted an alternative decision regarding revisions to the SRAC cost formulae that were implemented in 2009. The essence of the decision is to provide a 50/50 split between market and administrative heat rates for the calculation of the overall heat rate used in the compensation calculation. This increases the amount of variable operating cost included in the determination of SRAC amount. The SRAC change impacts the steam payment component of the PPAs described above and the Partnership is currently in discussion with the Navy on implications of future steam pricing.

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Colorado

        On April 19, 2010, the Colorado Legislature enacted House Bill 10-1365 (HB1365) which entitled the "Clean Air-Clean Jobs Act" (CACJA). CACJA requires PSCo to submit a plan to the Colorado Public Utilities Commission (CoPUC) to achieve 70 - 80% reductions in NOx emissions from a minimum of 900 MW of its existing coal generating facilities by December 31, 2017 with a CoPUC decision accepting, modifying or rejecting the plan required by December 15, 2010.

        The specific replacement options that will ultimately be approved for PSCo could have implications for future commercial contracting opportunities for the Partnership's Greeley facility. The existing Greeley PPA with PSCo expires in August 2013.

        The CoPUC issued a decision on December 15, 2010. The CoPUC did not select any of the packaged portfolios that were extensively modeled in the docket, but instead generated its own unique plan that incorporates elements of various plans. The decision directs PSCo to retire 551 MW of existing coal generation, add emissions controls to 742 MW of existing coal capacity, fuel-switch 463 MW of coal-capacity to natural gas, and construct a new 2x1 natural gas combined cycle facility with 569 MW capacity. The CoPUC did acknowledge other options, including gas turbines, IPP generation, and transmission, may be more effective long-term solutions than fuel-switching coal-to-natural gas units, and in this respect directed PSCo to present alternatives to fuel-switching coal-to-natural gas in its upcoming ERP due in late 2011.

        The decision preserves an option for the Partnership and other existing IPP facilities to bid into the next RFP. On January 4, 2011, seven parties, including PSCo and CIEA (on behalf of the Partnership and SWG), filed "Requests for Rehearing, Reargument or Reconsideration" (RRR Request) regarding various aspects of the decision. See "Legal Proceedings".


ENVIRONMENTAL MATTERS

        The Partnership has obtained all environmental licenses, permits, approvals and other authorizations required for the operation of its power plants. Except as outlined below, the Partnership is satisfied that its operating practices are in material compliance with applicable environmental laws and regulatory requirements. The power plants are operated in an environmentally sound manner and the environmental management systems are aligned with the corporate policies and procedures of Capital Power, which are binding upon the General Partner and the Manager.

        At the Calstock plant, opacity remains a concern while burning the landfill waste wood alone. A blend of fuel supply is utilized to mitigate opacity and particulate issues. However, Calstock is not meeting two other conditions in its Certificate of Approval (CoA): (i) attaining the minimum combustion gas temperature and residence time, and (ii) the maximum carbon monoxide concentration in the stack. The Partnership has submitted an application to the Ontario Ministry of Environment to amend the Certificate of Approval to more accurately reflect the operating conditions of the plant.


Environmental Regulation

        Many of the Partnership's operations are subject to extensive environmental laws, regulations and guidelines relating to the generation and transmission of electricity, pollution and protection of the environment, health and safety, greenhouse gas (GHG) and other air emissions, water usage, wastewater discharges, hazardous material handling, storage, treatment and disposal of waste and other materials and remediation of sites and land-use responsibility. These regulations can impose liability for compliance costs and costs to investigate and remediate contamination.

        The Partnership business is a significant emitter of carbon dioxide (CO2), NOx, sulphur dioxide (SO2), mercury and particulate matter (PM), and is required to comply with all licenses and permits and federal, provincial and state requirements, including programs to reduce or offset GHG emissions.

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        Compliance with new regulatory requirements may require the Partnership to incur significant capital expenditures or additional operating expenses, and failure to comply with such regulations could result in fines, penalties or the curtailment of operations. To the extent that proposed regulations are described below, until detailed regulations are enacted there is insufficient information to assess the impact on the Partnership, although as additional regulations are passed it is likely the Partnership will incur increased costs.

Canadian Federal Government—GHG Emissions Regulations

        On June 23, 2010, the Canadian Environment Minister announced the Government of Canada's plan for new GHG emission regulation for coal-fired electricity generation units. The proposed plan will apply a new GHG emissions performance standard to new coal-fired electricity generation units and facilitate phasing out conventional coal-fired electricity generation in an orderly manner. The regulations are anticipated to be effective July 1, 2015 and units that have commercial operation dates prior to July 1, 2015 are expected to be exempt from the regulation until they reach the end of their economic useful life. Because the proposed regulations address coal-fired generation assets they are not expected to have any negative impact on the Partnership's facilities.

Canadian Federal Government—Air Emission Regulations

        The Canadian government is considering regulations which may place stricter limits on NOx, SO2, mercury and PM emissions from fossil fuel-fired generating stations in Canada. The Canadian Department of Environment has been working with the provincial governments and industry to develop a regulatory framework to minimize local emissions under a Comprehensive Air Management System (CAMS) and the regulations are expected to be implemented in 2013.

Ontario

        The Ontario government aims to harmonize its cap and trade program with the Western Climate Initiative (WCI), which is represented by four provinces (B.C., Ontario, Quebec and Manitoba) and seven states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington). The WCI requires a 15% reduction in GHG emission levels by 2020, from those of 2005. The cap and trade system applicable to industrial facilities including electricity generation is expected to be implemented in 2012. However, the Ontario Government has not yet provided the industry specific GHG reduction targets or other program details.

British Columbia

        The Greenhouse Gas Reduction Targets Act and the Greenhouse Gas Reduction (Cap and Trade) Cap and Trade Act which were enacted in 2008, provide the statutory basis for establishing a market-based framework to reduce GHG emissions from large emitters. The BC Government aims to harmonize its cap and trade program with the WCI, similar to Ontario. The cap and trade system applicable to industrial facilities including electricity generation is expected to start in 2012 and will replace the current fuel tax. However, the BC Government has not yet provided the industry specific GHG reduction targets or other program details.

U.S.—Greenhouse Gas Regulation

        The U.S. Environmental Protection Agency (USEPA) and the state of California have implemented mandatory GHG reporting requirements, which are expected to be met by the Partnership on their respective due dates in 2011.

        The USEPA is expected to regulate GHGs under the Clean Air Act (CAA) with requirements for best available control technology for new GHG sources and major modifications of existing sources.

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They also plan to control GHG emissions for existing and new sources through new source performance standards.

        The WCI, as described above under Ontario, may affect the operation of the Partnership's four facilities in California and the Frederickson facility in Washington.

        California's proposed Cap and Trade program to control GHGs aims to cut the state's GHG emissions to 1990 levels by 2020 with further reductions each year thereafter. The initial phase of the program will apply to electric generation and large industrial units and is expected to be effective in January 2012, but the proposal's GHG emission allocation methodology has not yet been established. On November 2, 2010, a proposition (Proposition 23) to effectively repeal the program was rejected by California voters.

        There is currently insufficient information to determine the impact of the proposed regulations on the Partnership, however if additional regulations are passed it is likely that the Partnership will incur increased costs.

U.S.—Air Emission Regulations

        In July, 2010, USEPA proposed the Clean Air Transport Rule (CATR) to replace the Clean Air Interstate Rule. CATR proposes to reduce the amount of Nitrogen Oxide (NOx) and Sulphur Dioxide (SO2) emissions from electric generating units that are transported in the air to down-wind states. CATR proposes emission reductions sufficient to contribute to reducing NOx and SO2 measures below the ambient air quality standards in those down-wind states. The CATR proposals are also expected to significantly limit emissions trading.

        CATR only applies to units of generating facilities with a capacity of 25 MW or more, although it may be extended to other facilities when it is re-evaluated in 2014. Cogeneration facilities and units not providing electricity for sale on the electricity grid are also exempt. The Partnership units that may be impacted are Roxboro, Southport, and Morris, however, there is insufficient information to understand the implications of the proposed regulations.

        There is currently insufficient information to determine the impact of these air emission proposed regulations on the Partnership, however if additional regulations are passed it is likely that the Partnership will incur increased costs.

        In 2010, the USEPA proposed new air toxics standards, including standards for mercury, for industrial boilers (Boiler MACT) and for coal and oil-fired electric generating units. However, the state of North Carolina issued a maximum available control technology permit to the Partnership under the CAA, which precludes the application of these proposed new standards to its North Carolina facilities. In addition, based on the fuel mix and newly installed controls at the Partnership's North Carolina facilities, the Partnership does not anticipate the need for further mercury or other hazardous emissions controls at these facilities.

U.S.—Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

        CERCLA, also referred to as Superfund, requires investigation and remediation of sites where there has been a release or threatened release of hazardous substances. It also authorizes the USEPA to take response actions at Superfund sites, including ordering parties who are potentially responsible for the release to pay for their actions. Many states have similar laws. CERCLA defines potentially responsible broadly to include past and present owners and operators, as well as generators, of wastes sent to a site. The Partnership is currently not subject to any material liability for any Superfund matters. However, the Partnership generates certain wastes, including hazardous wastes, and sends certain of its wastes to third party waste disposal sites. As a result, there can be no assurance that the Partnership will not incur a liability under CERCLA in the future.

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COMPETITION

        During the terms of the PPAs, the obligations to purchase power generated by the power plants are firm up to the contract quantities and are not significantly affected by a competitive market for power in the jurisdictions and markets in which the power plants are located or the markets to which their power is sold. At the Williams Lake plant, any excess energy, approximately 20% of the total energy produced, is priced by reference to a power index. In 2009, the year end excess energy price ($58/MWh) was higher than the year end prices received for such excess energy in 2008 ($49/MWh). Except in that limited instance, (e.g. Williams Lake excess energy), the potential presence of lower or higher priced power in any of the electricity markets supplied by the power plants does not (subject to certain curtailment rights in the applicable PPAs), allow for a change either in the quantity of power required to be purchased under such agreements or the price payable for such power. During the term of a SPA, the obligations to purchase steam and other forms of thermal energy generated by the CHP facilities are fixed by the contract. While some areas may offer ready access to an alternate steam or thermal energy source, most would require the construction of new facilities and infrastructure by the customer or another third party to offer a competing supply. It is a competitive advantage to the CHP facilities to have their facilities and infrastructure in place and available to the customer.

        Ongoing research and development activities improve upon power technologies and reduce the cost of alternative methods of power generation. As the PPAs and SPAs expire the Partnership must re-contract plant capacity which may also involve capacity re-powering or upgrades in order to compete with more efficient plants utilizing newer technologies.

        Competition in the North American power generation market is comprised of numerous fully and partially-regulated utilities and independent power producers. However, with operational experience in four types of energy supply, a broad geographic footprint and good access to capital markets, the Partnership is well-positioned to compete for contracted generation assets.


Canada

        In its 2009 outlook of Canada's energy supply, the National Energy Board of Canada forecasts Canadian electricity production to grow at a compound average annual rate of over 1% between 2011 and 2020. The combined effect of demand growth and facility retirements is expected to result in a need for new generation in the coming years. The British Columbia and Ontario markets remain price regulated, and provincial regulatory bodies have continued to issue RFP's or other procurements for the development of new generation.


United States

        The U.S. Energy Information Administration in its 2010 Annual Energy Outlook forecasts U.S. electricity demand to grow at a compound average annual rate of over 1% between 2011 and 2020. In combination with limited near-term capacity development and anticipated retirements (particularly of aging coal plants), demand growth in the U.S. is expected to compress reserve margins and necessitate renewed development activity. Regional power markets within the U.S. exhibit a high level of diversity, due in part to differing regulatory regimes, transmission constraints, supply and demand characteristics and environmental policies. The U.S. market has solid growth potential for the Partnership due to its size relative to the Canadian market and because of its historical reliance on fossil fuel-based power generation which is an area of expertise for the Partnership.

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DISTRIBUTIONS OF THE PARTNERSHIP

        Cash distributions per Unit declared by the Partnership per year during the past three years are as follows:

 
  2010   2009   2008  

Cash distributions per Unit declared per year

  $ 1.76   $ 1.95   $ 2.52  

        Prior to October 1, 2009, the Partnership distributed cash to its limited partners on a quarterly basis. Commencing after September 30, 2009 the Partnership distributes cash to its limited partners on a monthly basis in accordance with the requirements of the Partnership Agreement and subject to the approval of the Board of Directors of the General Partner. Cash distributions are determined in consideration of cash amounts required for the operations of the Partnership and the power plants including maintenance capital expenditures, debt repayments, and financing charges, and any cash retained at the discretion of the Board of Directors of the General Partner to satisfy anticipated obligations or to normalize monthly distributions. The cash distributions are made in respect of each calendar month to Unitholders of record on the last day of each month commencing after September 30, 2009. Payments are made on or before the 30th day after each record date. See "General Development of the Business". In connection with the signing of the Memorandum of Agreement, the Partnership announced a reduction in distributions on Units from $0.63 per Unit per quarter to $0.44 per Unit per quarter effective with the June 2009 distribution. Distributions are prohibited by certain covenants under the Partnership's credit facilities, and pursuant to guarantees entered into in connection with the issue of preferred shares by CPEL, if an uncured default exists. See "Business Risks—Preferred Share guarantee—unit distribution risk" in the MD&A.

        In October 2009, the Partnership announced the launch of a Premium DistributionTM and Distribution Reinvestment Plan (the Plan) that provides eligible Unitholders with two alternatives to receiving the monthly cash distributions, including the option to accumulate additional Units in the Partnership by reinvesting cash distributions in additional Units issued at a 5% discount to the Average Market Price of such Units (as defined by the Plan) on the applicable distribution payment date. Under the Premium DistributionTM component of the Plan, eligible Unitholders may elect to exchange these additional Units for a cash payment equal to 102% of the regular cash distribution on the applicable distribution payment date. See "General Development of Business".


TM
Denotes a trademark of Canaccord Capital Corporation

        Additional information with respect to the Plan is available on the Partnership's website at www.capitalpowerincome.ca.


DIVIDENDS OF SUBSIDIARY (CPEL)

Series 1 Shares

        Cash dividends per share declared by CPEL per year with respect to the Series 1 Shares during the past three years are as follows:

 
  2010   2009   2008  

Cash dividends per share declared per year

    1.2125   $ 1.2125   $ 1.2125  

        Series 1 Shares pay cumulative dividends of $1.2125 per share per annum payable quarterly on the last business day of March, June, September and December of each year, as and when declared by the Board of Directors of CPEL.

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Series 2 Shares and Series 3 Shares

        CPEL paid an initial dividend of $0.28288 per share on December 31, 2009 on its Series 2 Shares for the period from November 2, 2009 to December 31, 2009. CPEL paid a fixed dividend of $1.75 per share per annum, payable quarterly, for the period from January 1, 2010 to December 31, 2010.

        Series 2 Shares pay fixed cumulative dividends of $1.75 per share per annum payable quarterly on the last business day of March, June, September and December of each year, as and when declared by the Board of Directors of CPEL, for an initial five-year period ending December 31, 2014. The dividend rate will reset on December 31, 2014 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.18%. The holders of Series 2 Shares will have the right to convert their shares into Series 3 Shares of CPEL, subject to certain conditions, on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 3 Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the Board of Directors of CPEL, at a rate equal to the sum of the then 90-day Government of Canada Treasury bill rate and 4.18%.

        CPEL confirms that the dividends for Series 1 Shares and Series 2 Shares are 100% eligible dividends as defined by the Income Tax Act (Canada) (Tax Act). Under this legislation, individuals resident in Canada may be entitled to enhanced dividend tax credits that reduce the income tax otherwise payable.


CAPITAL STRUCTURE

        The Partnership is authorized to issue an unlimited number of Units and an unlimited number of subscription receipts exchangeable into Units. Any limited partner who holds Units has represented, warranted and covenanted under the Partnership Agreement that they are not a non-resident of Canada for purposes of the Tax Act or, if a partnership, is a Canadian Partnership under the Tax Act. The Partnership Agreement itself contains restrictions on Unit ownership outside of Canada. The limited partners have further covenanted not to transfer their Units to any person including corporate or other entities which are not able to give these representations, warranties or covenants. Compliance with these covenants is monitored by regular review of a registered Unitholder list provided by the Partnership's transfer agent. Distributions will be withheld from non-residents.


Nature of Units

        Unitholders do not have the right to elect directors of the General Partner or to appoint auditors of the Partnership. In addition, Unitholders do not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring oppression or derivative actions.


Votes of the Limited Partners

        Generally there are no meetings of the limited partners as the Partnership Agreement requires Unitholder votes in only limited circumstances. CPI Investments, as the owner of all of the shares of the General Partner, elects the directors of the General Partner. However, under the Partnership Agreement, the General Partner or limited partners holding not less than 10% of the outstanding Units may request a meeting which shall be convened within 60 days of receipt of notice of the meeting. A quorum will consist of one or more limited partners present in person or by proxy holding at least 10% of the outstanding Units.

        Extraordinary Resolutions (as defined in the Partnership Agreement) will be decided by a poll allowing one vote for each Unit held by the person present as shown on the record as a limited partner at the record date and for each Unit in respect of which the person is the proxy holder. Extraordinary

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resolutions of the Unitholders are required to approve certain matters, including certain amendments to the Partnership Agreement, in certain circumstances the removal or voluntary withdrawal of the General Partner as general partner, the dissolution of the Partnership, the sale, exchange or other disposition of all or substantially all of the property of the Partnership, and the waiving of any default on the part of the General Partner.

        Ordinary resolutions will be decided by a show of hands unless otherwise required by the Partnership Agreement or a poll is demanded by a limited partner. Ordinary resolutions of the Unitholders are required to approve certain matters, including in certain circumstances the removal of the General Partner as general partner.

        Securities laws in Canada and the rules of the TSX also provide Unitholders with the right to vote in certain circumstances, such as on the approval of "related party transactions", and on certain significant private placement and acquisition transactions.


Dissolution

        In the event of dissolution, the General Partner (or, in specified circumstances, such other person as may be appointed by ordinary resolution) shall act as receiver and liquidator of the assets of the Partnership and shall provide for the payment of all liabilities of the Partnership and distribute the balance of assets remaining after payment of creditors to Unitholders proportionate to the number of Units held by them.


Preferred Shares of CPEL

        CPEL is authorized to issue an unlimited number of Preferred Shares issuable in series, of which up to 5,750,000 Series 1 Shares, 4,000,000 Series 2 Shares and 4,000,000 Series 3 Shares have been authorized for issuance.

        Except as required by law or in the conditions attaching to the Preferred Shares as a class, the holders of Series 1 Shares, Series 2 Shares and Series 3 Shares are not entitled to vote at any meeting of shareholders of CPEL, unless and until CPEL has failed to pay eight quarterly dividends and for as long as any such dividends remain in arrears.

        On May 25, 2007, CPEL issued 5,000,000 Series 1 Shares for gross proceeds of $125 million. Pursuant to a guarantee indenture dated May 25, 2007 among the Partnership, CPEL and CIBC Mellon Trust Company, the Partnership agreed to fully and unconditionally guarantee the Series 1 Shares on a subordinated basis as to: (i) payment of dividends, as and when declared; (ii) payment of amounts due on redemption of the Series 1 Shares; and (iii) payment of amounts due on liquidation, dissolution or winding up of CPEL.

        On November 2, 2009, CPEL issued 4,000,000 Series 2 Shares for gross proceeds of $100 million. The holders of Series 2 Shares will have the right to convert their shares into Series 3 Shares of CPEL, subject to certain conditions, on December 31, 2014 and on December 31 of every fifth year thereafter. Pursuant to guarantee indentures each dated November 2, 2009 among the Partnership, CPEL and Computershare Trust Company of Canada, the Partnership agreed to fully and unconditionally guarantee the Series 2 Shares and Series 3 Shares on a subordinated basis as to: (i) the payment of the dividends, as and when declared; (ii) the amounts payable on a redemption of Series 2 Shares or Series 3 Shares for cash; and (iii) the amounts payable in the event of the liquidation, dissolution and winding up of CPEL.

        The guarantee indentures for the Series 1 Shares, Series 2 Shares and Series 3 Shares provide that if, and for so long as, the declaration or payment of dividends on the Series 1 Shares, Series 2 Shares or Series 3 Shares is in arrears, the Partnership will not make any distributions on the Units. See "Business Risks—Preferred Share guarantee—unit distribution risk" in the MD&A.

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Debt Financing

Credit Facilities

        The Partnership currently has in place approximately $365 million in total credit facilities consisting of three revolving credit facilities totalling $325 million with three Canadian chartered banks, a $20 million demand credit facility with a Canadian chartered bank and a US$20 million demand credit facility with a US tier 1 bank. Each of the revolving credit facilities is unsecured, bears interest at market rates and has two-year terms maturing in June 2012, September 2012 and October 2012, subject to extension. As at December 31, 2010, the combined Canadian dollar equivalent of $86.1 million was utilized under these facilities. Under the revolving credit facilities, the Partnership must maintain a debt-to-capitalization ratio of not more than 65% as at the end of each quarter. In addition, in the event the Partnership is assigned a rating of less than BBB+ by Standard & Poor's (S&P) and less than BBB (high) by DBRS Limited (DBRS), the Partnership must also maintain a ratio of EBITDA (earnings before interest, income taxes, depreciation and amortization as defined in the respective credit facilities) to interest expense of not less than 2.5 to 1.0, measured quarterly. If an event of default has occurred and is continuing under such facilities, the Partnership may not declare, make or pay distributions (subject to certain limited exceptions). As at December 31, 2010, the Partnership was in compliance with its financial covenants and was not in default under its revolving credit facilities. There are no similar financial covenants in the demand facilities. The demand credit facilities are unsecured and bear interest at floating rates plus a spread.

Medium Term Notes Program

        On June 23, 2006, the Partnership issued $210 million of unsecured medium term notes (MTNs) under a note indenture (the Note Indenture) dated June 15, 2006. The $210 million principal amount of MTNs outstanding is due June 23, 2036 and bears interest at 5.95% per annum. The Note Indenture does not limit the aggregate principal amount of MTNs that may be issued thereunder. Additional MTNs maturing at varying dates and bearing interest at different rates, in each case as determined by the Partnership, may be issued under the Note Indenture. Under the Note Indenture, the Partnership must maintain a debt-to-capitalization ratio of not more than 65%.

Senior Notes

        On August 15, 2007, CPUSGP, issued an aggregate of US$150 million principal amount of 5.87% Senior Notes due August 15, 2017 and an aggregate of US$75 million principal amount of 5.97% Senior Notes due August 15, 2019, each guaranteed by the Partnership. Under the terms of the Senior Notes, the Partnership must maintain a debt-to-capitalization ratio of not more than 65%.


RATINGS

Debt Ratings

        The Partnership has been assigned a debt rating for the Partnership's Senior Notes by S&P and DBRS.

        S&P has assigned the Partnership a credit rating of BBB (stable). The "BBB" rating is the fourth highest rating out of 10 rating categories for S&P's long-term issuer credit ratings. According to S&P, an obligor rated "BBB" has adequate capacity to meet its financial commitments. However adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. The stable outlook reflects S&P's view that the Partnership will continue to generate relatively stable revenue and cash flow from its diversified portfolio of generating assets supported by PPAs largely with investment-grade off-takers and well-spread expiries.

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        DBRS has assigned the Partnership's long-term debt a credit rating of BBB (high). This rating is DBRS's fourth highest of 10 categories. Long-term debt rated "BBB" by DBRS is of adequate credit quality. According to DBRS, protection of interest and principal is considered acceptable, but the entity is fairly susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of the entity and its rated securities. The assignment of a "high" or "low" modifier indicates the relative standing within the rating category. As a result of the announcement of the strategic review process, DBRS placed this rating under review with negative implications.


Stability Rating

        The Partnership has also been assigned a Stability Rating by DBRS.

        DBRS has assigned the Partnership a stability rating of STA-2 (low). STA-2 is the second highest of seven categories in DBRS's rating system for income fund stability. DBRS further subcategorizes each rating category by the designation high, middle and low to indicate where an entity falls within the rating category. According to DBRS, income funds rated STA-2 have very good distributions per unit stability and sustainability, exhibit performance that is only slightly below the STA-1 category, typically show above-average strength in areas of consideration, and possess levels of distributable income per unit that are not likely to be significantly negatively affected by foreseeable events. According to DBRS, income funds rated STA-2 are above average in many, if not most, areas of consideration.


Preferred Shares Ratings

        The preferred shares issued by CPEL have been assigned Preferred Share Ratings by S&P and DBRS.

        S&P has assigned the Series 1 Shares and Series 2 Shares a rating of P-3 (high). Such P-3 (high) rating is the ninth highest of twenty ratings used by S&P in its preferred share rating scale. According to S&P, a P-3 (high) rating indicates that, although the obligation has some quality and protective characteristics, the obligor faces major ongoing uncertainties, and exposure to adverse business, financial, or economic conditions, which could lead to the obligor's inadequate capacity to meet its financial commitments.

        DBRS has assigned the Series 1 Shares and Series 2 Shares a rating of Pfd-3 with a negative trend. The Pfd-3 rating is the third highest of six rating categories used by DBRS for preferred shares. According to DBRS, preferred shares rated Pfd-3 are of adequate credit quality and, while protection of dividends and principal is still considered acceptable for such preferred shares, the issuing entity of preferred shares with a Pfd-3 rating is considered to be more susceptible to adverse changes in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection. DBRS further subcategorizes each rating by the designation of "high" and "low" to indicate where an entity falls within the rating category. The absence of either a "high" or "low" designation indicates the rating is in the middle of the category. The rating trend indicates the direction in which DBRS considers the rating is headed should present tendencies continue, or in some cases, unless challenges are addressed.


Ratings Summary

        Ratings are intended to provide investors with an independent assessment of the credit quality of an issue or an issuer of securities and such ratings do not address the suitability of a particular security for a particular investor. The ratings assigned to a security may not reflect the potential impact of all risks on the value of a security. The above ratings are not a recommendation to buy, sell or hold securities of the Partnership and may be subject to revision or withdrawal at any time by the applicable rating organization.

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MARKET FOR SECURITIES

        The Units trade under the symbol CPA.UN.


Toronto Stock Exchange 2010 Trading Statistics:

 
  Unit Price    
 
 
  Volume
Traded
 
Month
  High   Low   Close  

January

  $ 17.24   $ 15.54   $ 16.76     1,809,591  

February

  $ 16.98   $ 15.91   $ 16.51     1,238,618  

March

  $ 18.43   $ 16.50   $ 17.82     1,763,684  

April

  $ 18.14   $ 16.80   $ 17.18     1,463,942  

May

  $ 17.31   $ 15.05   $ 16.67     1,773,034  

June

  $ 16.59   $ 15.38   $ 16.30     1,834,995  

July

  $ 17.90   $ 16.03   $ 17.68     1,470,997  

August

  $ 18.01   $ 16.96   $ 18.01     1,275,618  

September

  $ 18.85   $ 17.65   $ 18.75     1,433,610  

October

  $ 19.02   $ 17.81   $ 18.33     1,395,389  

November

  $ 18.54   $ 17.75   $ 17.91     1,497,626  

December

  $ 18.10   $ 17.11   $ 17.95     1,566,002  


MANAGEMENT OF THE PARTNERSHIP

General

        The business and affairs of the Partnership are managed by the General Partner pursuant to the Partnership Agreement. Management services are provided by the Manager, and its affiliates, for and on behalf of the General Partner and the Partnership's subsidiaries, pursuant to the Management and Operations Agreements, pursuant to which the Manager is to provide, perform, or cause to be provided and performed, management and administrative services for the Partnership and operations and maintenance services for the power plants. Such services include, without limitation, advice and consultation regarding the affairs of the Partnership, its business planning, support, guidance and policy making, general management services and the management and operation of the power plants. The Manager relies on its resources and those of its affiliates in providing services to the Partnership under the Management and Operations Agreements. See "Interests of Management and Others in Material Transactions".

        Certain of the officers and directors of the Manager are also officers or directors of Capital Power, and/or the General Partner. The Management and Operations Agreements are generally long term and are reviewed by the Partnership's Independent Directors Committee from time to time. See "Interests of Management and Others in Material Transactions".

        The Partnership Agreement sets out the rights and duties of the limited partners as well as the General Partner. Under its terms, the business of the Partnership is restricted to direct or indirect participation in the energy supply industry.

        The Partnership Agreement contains other provisions important to Unitholders. A copy is available on the Partnership's website at www.capitalpowerincome.ca or upon request to the Corporate Secretary of the General Partner or under the Partnership's profile on SEDAR at www.sedar.com.


The General Partner

        The General Partner was incorporated on February 13, 1997 under the Canada Business Corporations Act. The General Partner is a wholly-owned subsidiary of CPI Investments. EPCOR owns all of the 51 voting non-participating shares of CPI Investments and Capital Power owns all of the 49 voting, participating shares of CPI Investments. Pursuant to the Shareholder Agreement in respect of

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CPI Investments, Capital Power L.P. and EPCOR agreed that: (i) the board of directors of CPI Investments shall consist of three directors; and (ii) EPCOR is entitled to nominate one person for election to the board of directors of CPI Investments. Under the Partnership Agreement, the General Partner is prohibited from undertaking any business activity other than acting as General Partner of the Partnership.


BOARD OF DIRECTORS AND EXECUTIVE OFFICERS

        The Board of Directors of the General Partner has plenary power and is responsible for the stewardship of the Partnership. The Board of Directors' Terms of Reference provide that its primary responsibility is to foster the long-term success of the Partnership consistent with the requirements set out in the Partnership Agreement and the Board's fiduciary responsibility to the Unitholders. As part of its mandate, the Board has the responsibility to seek to ensure that management has identified the principal risks of the Partnership's business and has implemented appropriate systems and strategies to manage these risks.

        The Partnership Agreement does not entitle Unitholders to elect directors of the General Partner but rather requires that at least three directors be independent of Capital Power or its affiliates and EPCOR or its affiliates provided Capital Power and its affiliates and EPCOR and its affiliates together own at least 30% of the issued and outstanding Units. Should Capital Power and its affiliates and EPCOR and its affiliates not maintain a 30% ownership holding in the Partnership (or such lower percentage, being not less than 20%, resulting from the issuance of Units other than to Capital Power and its affiliates or EPCOR and its affiliates), not less than four directors must be independent. Capital Power's (including its Affiliates) ownership is approximately 29.6% as a result of the issuance of Units to other Unitholders under the Partnership's distribution reinvestment plan, and so the board of directors of the General Partner must have at least three directors who are independent. The Board has determined that, notwithstanding the Partnership Agreement, it is appropriate and in the interests of Unitholders and good governance that an additional independent director, as defined under Canadian securities laws, be appointed to the General Partner's Board. The Board of Directors now consists of four independent directors, as defined under Canadian securities laws, three directors who are senior officers of Capital Power, and one director who is a former senior officer of Capital Power.

        The four independent members of the Board of Directors are not members of management of Capital Power and are independent, as that term is defined in National Instrument 58-101—Disclosure of Corporate Governance Practices (NI 58-101). Under NI 58-101, a director is independent if he or she would be independent within the meaning of independence under Section 1.4 of National Instrument 52-110—Audit Committees (NI 52-110). Under NI 52-110, a director is independent if he or she has no direct or indirect material relationship with the Partnership. A material relationship is a relationship which could, in the view of the Board, be reasonably expected to interfere with the exercise of a director's independent judgment. The Board has determined that each of the four independent directors is independent for the purpose of NI 58-101 on the basis that he does not have any relationship with the Partnership which could reasonably be expected to interfere with the exercise of his independent judgement. The Board has determined that each of the other directors is not independent for the purpose of NI 58-101 on the basis that each is a member of senior management of Capital Power.


Directors and Officers

        The following tables set out the full name, province/state and country of residence, date of birth and office for each individual that was a director or officer of the Partnership as at December 31, 2010, as well as their principal occupations during the past five years.

Remainder of page left intentionally blank

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Directors

Name, Province/State and Country of
Residence, and Date became a Director
and Units held(1)(2)
  Office Held and
2010 Board &
Committee
Meetings Attended
  Principal Occupation During the Past
Five Years
  Director of Other
Reporting Issuers

Graham L. Brown(8)
Alberta, Canada
December 12, 2008
Units held: Nil(5)
Date of Birth: January, 1953

  Director
11 of 13 Board
  Senior Vice President, Operations of Capital Power Corporation from July, 2009; prior thereto, Senior Vice President of EPCOR USA Inc. from May 2008 to June 2009; prior thereto, Vice President, Operations of EPCOR USA Inc. from January 2007; prior thereto, Director, Eastern of EPCOR Regional from September 2005; prior thereto, Production Manager, Ontario Power Generation from 2003.    

Brian A. Felesky, CM, QC(3)(4)(10)
Alberta, Canada
June 18, 1997
Units held: Nil(5)
Date of Birth: November, 1943

 


Director
13 of 13 Board
9 of 10 Independent Directors
5 of 5 Audit
20 of 20 Special

 


Counsel with Felesky Flynn LLP (law firm) from December 2006; prior thereto Partner of Felesky Flynn LLP.

 


Precision Drilling Corporation, RS Technologies Inc., Cequence Energy Ltd.

Allen R. Hagerman, FCA(3)(4)(6)(10)
Alberta, Canada
February 26, 2003
Units held: 16,873(5)
Date of Birth: May, 1951

 


Director
13 of 13 Board
10 of 10 Independent Directors
5 of 5 Audit
3 of 3 Governance
20 of 20 Special

 


Executive Vice President of Canadian Oil Sands Limited (oil and gas) from April 2007 to present; prior thereto, Chief Financial Officer of Canadian Oil Sands Limited from June 2003.

 


Precision Drilling Corporation

Francois L. Poirier(3)(4)(10)(11)
Ontario, Canada
April 2, 2007
Units held: 3,100(5)
Date of Birth: July, 1966

 

Director
13 of 13 Board
10 of 10 Independent Directors
5 of 5 Audit
20 of 20 Special

 

Part-time instructor at Schulich School of Business (York University) from September 2007 to 2009; prior thereto, Managing Director and Group Head, Power Investment Banking Division, JP Morgan Securities, Inc., (financial services) from August 2005; prior thereto, Managing Director, Power Investment Banking from May 2001.

 

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Name, Province/State and Country of
Residence, and Date became a Director
and Units held(1)(2)
  Office Held and
2010 Board &
Committee
Meetings Attended
  Principal Occupation During the Past
Five Years
  Director of Other
Reporting Issuers

Brian T. Vaasjo(6)
Alberta, Canada
August 31, 2005
Units held: 7,400(5)
Date of Birth: August, 1955

 

Chairman and Director
13 of 13 Board
3 of 3 Governance

 

President and Chief Executive Officer of Capital Power Corporation from July 2009 to present; prior thereto, Executive Vice President of EPCOR Utilities Inc. from April 2005; prior thereto, Executive Vice President and President, Energy Services for EPCOR Utilities Inc. from July 2001.

 

Capital Power Corporation

Rodney D. Wimer(4)(6)(10)
Oregon, U.S.
January 17, 2006
Units held: Nil(5)
Date of Birth: August, 1949

 

Director
13 of 13 Board
10 of 10 Independent Directors
3 of 3 Governance
19 of 20 Special

 

Managing Director of Mazama Capital Partners LLC (private investments and asset management) since October 2002; General Partner of Fulcrum Power Services L.P. from October 2002 to September 2009 and a director from October 2002 to December 2010; prior thereto, President, Commercial Power Division of Dynegy Inc. (energy marketing) from March 2001 to January 2002.

 

Fairborne Energy Ltd.

James Oosterbaan(9)
Alberta Canada
June 24, 2009
Units held: Nil(5)
Date of Birth: February, 1960

 

Director
13 of 13 Board

 

Senior Vice President, Commercial Services of Capital Power Corporation from July 2009; prior thereto, Senior Vice President of EPCOR Merchant & Capital and EPCOR Alberta from April 2004.

   

Stuart A. Lee(7)(11)
Alberta, Canada
February 22, 2010
Units held: 3,536(5)
Date of Birth: June, 1964

 

Director and President
13 of 13 Board

 

Senior Vice President, and Chief Financial Officer of Capital Power Corporation and President of CPI Income Services Ltd. from July 2009 to present; prior thereto, Chief Financial Officer of EPCOR Power Services Ltd. (now CPI Income Services Ltd.) from September 2005 and Vice President and Controller of EPCOR Utilities Inc. from July 2003 to July 2009.

   

(1)
The Board does not have an executive committee.

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(2)
Directors are elected until the close of the next annual meeting of the shareholder of the General Partner, or the effective date of a resolution in writing of the shareholder of the General Partner removing the directors from office, or the effective date of their resignation in writing in lieu thereof.

(3)
Member of the Audit Committee.

(4)
Independent Director and Member of the Independent Directors Committee. The other Directors are Officers of Capital Power and are therefore not Independent Directors under applicable Canadian securities law.

(5)
Represents as of December 31, 2010 the number of Units of the Partnership beneficially owned, or controlled or directed, directly or indirectly, by such persons. See "Director Compensation".

(6)
Member of the Governance Committee.

(7)
Mr. Lee was appointed as Director effective February 22, 2010.

(8)
Mr. Brown retired effective January 4, 2011 from his position as Senior Vice President, Operations of Capital Power Corporation.

(9)
Mr. Oosterbaan was appointed Senior Vice President, Operations & Commodity Portfolio Management of Capital Power Corporation on January 4, 2011.

(10)
Member of the Special Committee.

(11)
Member of the Strategic Review Sub-Committee.

        Additional biographical information regarding the current directors of the General Partner is set forth below.

Brian T. Vaasjo

        Brian Vaasjo has been President and Chief Executive Officer of Capital Power Corporation since July, 2009. Mr. Vaasjo was Executive Vice President of EPCOR Utilities Inc. until July, 2009, and was President of EPCOR's Energy Division from July, 2001 to April, 2005. Mr. Vaasjo was chiefly responsible for regional power generation and water operations. One of his primary responsibilities was advancing the company's competitive power and water businesses across North America including the clean coal initiatives. Mr. Vaasjo was also President of the Partnership from September 2005 until July 2009. Mr. Vaasjo is currently the Chair and a director of the General Partner.

        Mr. Vaasjo joined EPCOR in 1998 as Executive Vice President and Chief Financial Officer. Mr. Vaasjo led EPCOR's initial public offering of debentures and preferred shares. After joining EPCOR, Mr. Vaasjo was responsible for EPCOR's development and acquisition activity for most of his tenure with EPCOR, including the Genesee 3 project and the UE Waterheater Income Fund spin-off. Before joining EPCOR, Mr. Vaasjo spent 19 years with the Enbridge Group of Companies. At Enbridge, Mr. Vaasjo led or played a substantial role in the Consumers Gas acquisition, development of the Alliance and Vector Natural Gas Pipelines and the initial public offering of the Lakehead Pipeline Partners LP among other initiatives.

        Mr. Vaasjo holds a Master of Business Administration from the University of Alberta where he also received his undergraduate degree. Mr. Vaasjo is a Fellow of the Society of Management Accountants. Mr. Vaasjo also attended the University of Western Ontario Executive Program. In addition, he is a past Chairman of the board of the United Way, Alberta Capital Region, and a member of the Financial Executives Institute of Canada and is a board member for the Alberta Shock Trauma Air Rescue Society.

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Graham L. Brown

        Mr. Brown was Senior Vice President, Operations of Capital Power Corporation until his retirement on January 4, 2011. Prior to becoming Senior Vice President, Operations of Capital Power Corporation, Mr. Brown joined what is now CP Regional Power Services Limited Partnership as Director of Eastern Operations in 2005 where his chief role included maximizing plant revenues while improving efficiency, safety and environmental compliance. In November 2006, the Partnership purchased Ventures where his experience in managing hydro, solid fuel, natural gas turbine and renewable energy plants proved highly valuable as he assumed the role of Vice President of Operations for Ventures in January 2007.

        Mr. Brown began his career at GEC Gas Turbines Ltd. in Leicester, England in 1975 where he spent seven years building, operating and maintaining natural gas turbine power plants and gas pumping stations in the United Kingdom, Europe and the U.S. In 1982, he immigrated to Canada to join Ontario Hydro (subsequently Ontario Power Generation) and was involved in power operations for the next 23 years.

        Mr. Brown is from Manchester, England, and is a graduate of Mechanical Engineering from Leicester Polytechnic, Leicester, England as well as a Certified Professional Engineer since 1988 and a member of the Institute of Corporate Directors since 2009.

Brian A. Felesky

        Mr. Felesky is counsel at the law firm of Felesky Flynn LLP in Calgary, Alberta. He is a senior tax practitioner involved in structuring company reorganizations, acquisitions and spin-offs. He is also a member of the board of Precision Drilling Corporation, RS Technologies Inc., Cequence Energy Ltd. and various private corporations. He is a member of the audit committee of RS Technologies Inc. and chair of the audit committee of Cequence Energy Ltd. Mr. Felesky is actively involved in not-for-profit and charitable organizations. He is the co-chair of Homefront on Domestic Violence, a member of the senate of Athol Murray College of Notre Dame, board member of the Calgary Stampede Foundation, a Council member of the Alberta Order of Excellence, and a member of the Calgary Executive of the Institute of Corporate Directors.

        Mr. Felesky is a Queen's Counsel and Member of the Order of Canada. He is a recipient of an honorary doctorate of Laws from the University of Calgary. He is a graduate of and holds the ICD.D certification from the Institute of Corporate Directors (ICD).

Allen R. Hagerman, FCA

        Mr. Hagerman is currently Executive Vice President of Canadian Oil Sands Limited and prior to 2007 was Chief Financial Officer of Canadian Oil Sands Limited. Mr. Hagerman is a Director of Precision Drilling Corporation and the Calgary Exhibition and Stampede.

        Mr. Hagerman received a Bachelor of Commerce degree from the University of Alberta, a Masters of Business Administration from the Harvard Business School and is a chartered accountant with a corporate finance qualification with the Canadian Institute of Chartered Accountants. He is a graduate of and holds the ICD.D certification from the ICD.

        Mr. Hagerman is a Fellow of the Alberta Institute of Chartered Accountants, past Chair of the Alberta Children's Hospital Foundation and past President of the Financial Executives Institute, Calgary Chapter.

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Francois L. Poirier

        Mr. Poirier had a 20 year career in management consulting and financial services, most recently as Managing Director and Group Head of Power Investment Banking for JP Morgan Securities in New York. He has advised on mergers and acquisitions, for both buyers and sellers; led leveraged buyouts; structured project financing; and issued common stock and convertible securities for companies in the energy sector. Mr. Poirier has also lectured on private equity at the Schulich School of Business, York University.

        Mr. Poirier received a Bachelor of Operations Research from the University of Ottawa and a Masters of Business Administration from the Schulich School of Business at York University.

        Mr. Poirier currently serves as Vice Chairman on the board of one not-for-profit entity, The North York Harvest Food Bank. He is a graduate of and holds the ICD.D certification from the ICD.

Rodney D. Wimer

        Mr. Wimer is Managing Director of Mazama Capital Partners LLC (a private investment firm) and a limited partner of Fulcrum Power Services L.P (energy) since October 2002. Mr. Wimer was general partner of Fulcrum Energy LLC from October 2002 to September 2009 and director from October 2002 to December 2010. Prior thereto, he was President of the Commercial Power Division of Dynegy, Inc. from March 2001 until his retirement in January 2002.

        Mr. Wimer is a graduate of the Stanford University Executive Program and attended the Advanced Management Program of Phillips Petroleum Company. He has an undergraduate degree in Earth Sciences from Eastern Washington University and completed post-graduate work in geography and earth sciences at Portland State University.

James Oosterbaan

        Mr. Oosterbaan was Senior Vice President, Commercial Services of Capital Power Corporation until January 4, 2011, when he was appointed Senior Vice President, Operations & Commodity Portfolio Management of Capital Power Corporation. Prior thereto, he was Senior Vice President at EPCOR, responsible for the competitive power and water businesses in Alberta. Mr. Oosterbaan joined EPCOR in 2001. His areas of focus were business development, major project construction, commodity trading, water and power plant operations, and sales to end use customers. During his time at EPCOR, Mr. Oosterbaan was successful in guiding and further developing EPCOR's competitive water and power and commodity trading businesses through the deregulation of the Alberta electricity markets.

        Prior to joining EPCOR, Mr. Oosterbaan was a consultant in the energy and information technology sectors, and employed with the Westcoast Energy Group of Companies. While at Westcoast, he had management responsibilities in the areas of marketing, business development, forecasting, natural gas supply portfolio management, and regulatory affairs.

        Mr. Oosterbaan is a graduate of Stanford University's Executive Management Program. He holds a Master of Business Administration from the Ivey School of Business and a Bachelor of Business Administration (Honours) from Wilfred Laurier University.

Stuart A. Lee

        Mr. Lee is Senior Vice President and Chief Financial Officer of Capital Power Corporation. He has led several equity and debt offerings to finance the Partnership's acquisitions. He joined EPCOR in 2003 as Vice President and Corporate Controller.

        Mr. Lee is a chartered accountant who articled with one of the large international accounting firms. Prior to joining EPCOR, Mr. Lee worked for five years for Celanese Canada Inc., a large

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petrochemical manufacturer, as Vice-President and Controller where he was responsible for the reporting, treasury, tax, IT and supply chain functions for the Canadian operations. Mr. Lee has more than 23 years of relevant financial and reporting experience.


Officers(1)

Name, Province/State and Country of Residence, and Date became an Officer and Units held
  Title   Principal Occupation During the Past Five Years
B. Kathryn Chisholm
Alberta, Canada
August 31, 2005
Units held: 1,316(2)
Date of Birth: May, 1963
  Senior Vice President, General Counsel and Corporate Secretary   Senior Vice President, General Counsel and Corporate Secretary of Capital Power Corporation from July 2009 to present; prior thereto, Senior Vice President, General Counsel and Corporate Secretary of EPCOR Utilities Inc. from May 2005; prior thereto, Associate General Counsel of EPCOR Utilities Inc. from September 2004.

Peter D. Johanson
Alberta, Canada
May 8, 2009
Units held: 400(2)
Date of Birth: August, 1971

 

Controller

 

Controller of CPI Income Services Ltd. from July 2009 to present; prior thereto, Controller of EPCOR Power from November 2008; prior thereto, Senior Finance Manager of EPCOR Utilities Inc. from December 2006; prior thereto, Manager, Asset Valuation of EPCOR Utilities Inc. from April 2003.

John D. H. Patterson
Alberta, Canada
May 9, 2008
Units held: 2,353(2)
Date of Birth: June, 1946

 

Vice President and Treasurer

 

Vice President and Treasurer, Capital Power Corporation from July 2009; prior thereto, Vice President and Treasurer, EPCOR Power Services Ltd., EPCOR Power L.P. and subsidiaries from April 2007 and Vice President and Treasurer, EPCOR Utilities Inc. and subsidiaries from November 2005; prior thereto, Assistant Treasurer, EPCOR Utilities Inc. and subsidiaries from January 2000.

Leah M. Fitzgerald
Alberta, Canada
July 9, 2009
Units held: <1(2)
Date of Birth: August, 1967

 

Assistant Corporate Secretary

 

Associate General Counsel and Assistant Corporate Secretary of Capital Power Corporation from November 2010 to present; prior thereto, Director, Ethics and Assistant Corporate Secretary of Capital Power Corporation from July 2009 to November 2010; prior thereto, Chief Compliance Officer of EPCOR Utilities Inc. from October 2007; prior thereto, Associate Lawyer for Field LLP (law firm) from July 2006; prior thereto, Associate Lawyer for Brownlee LLP (law firm) from September 2002.

Anthony Scozzafava
Alberta, Canada
June 24, 2009
Units Held: 2,309(2)
Date of Birth: February, 1967

 

Chief Financial Officer

 

Vice President, Taxation of Capital Power Corporation from July 2009 to present and Chief Financial Officer of the CPI Income Services Ltd. from June, 2009 to present; prior thereto, Vice President, Taxation of EPCOR Utilities Inc. from July 2001.

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Name, Province/State and Country of Residence, and Date became an Officer and Units held
  Title   Principal Occupation During the Past Five Years

David Hermanson
Illinois, U.S.
Units Held: Nil(2)
Date of Birth: August, 1957

 

Vice President, Operations of Capital Power U.S.A.(3)

 

Vice President, Operations of Capital Power U.S.A. from July 2009 to present; prior thereto Vice President Operations at EPCOR USA from May 2008; prior thereto General Manager at EPCOR USA from November 2006 to April 2008; General Manager of Primary Energy from January 2005 to October 2006.

(1)
Stuart Lee, who is President of the Partnership, is included in the Directors table. Brian Vaasjo and Graham Brown are also included in the Directors table. Each of Messrs. Vaasjo, Lee and Brown performs a role as or similar to an executive officer of the Partnership.

(2)
Represents as of December 31, 2010, the number of Units of the Partnership beneficially owned, or controlled or directed, directly or indirectly, by such persons.

(3)
Mr. Hermanson performs a role as or similar to an executive officer of the Partnership.

        As at December 31, 2010, the directors of the General Partner who are not also executive officers of the General Partner, as a group, beneficially owned, or controlled or directed, directly or indirectly, 27,373 Units ($17.95 per Unit as at the close of trading on December 31, 2010 for a value of $491,345) which is less than 1% of the issued and outstanding Units.

        As at December 31, 2010, the directors and executive officers of the General Partner, as a group, beneficially owned, or controlled or directed, directly or indirectly, 37,335 Units ($17.95 per unit as at the close of trading on December 31, 2010 for a value of $670,163) which is less than 1% of the issued and outstanding Units.


Committees of the Board

Board of Directors / Governance Committee / Audit Committee / Independent Directors Committee

        The governance of the Partnership is the responsibility of the Board and the rights, authority and limitations on the General Partner are described in the Partnership Agreement.

        The Partnership is structured such that the role of the Chair and President of the General Partner are split between two individuals. The Chair, who is the President and Chief Executive Officer of Capital Power, has a casting vote or second vote in case of a tie vote at any meeting of the Board. In addition, the Board has appointed a Lead Director who is an independent director.

        The Chair's prime responsibility is seeking to ensure the effective operation of the Board of Directors by managing Board and Unitholder meetings, monitoring and overseeing the strategic agenda of the Partnership, and providing leadership and advice respecting the General Partner's business planning processes and the Partnership's corporate governance.

        The President of the General Partner provides day-to-day leadership and management to the General Partner and represents Management on the Board. The President's primary duties and objectives include: leading the General Partner; managing the Partnership's relationship with limited partners and the investment community; formulating strategies and plans and presenting them to the Board for approval; seeking to ensure that information management processes support the early identification of issues appropriately addressed by the Board; keeping the Board fully informed of the Partnership's progress toward achievement of its goals, objectives and policies in a timely and candid manner by managing the supporting material provided to the Board; leading the delivery of all functions provided for in the Management and Operations Agreements; leading the search for accretive

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transactions for presentation to the Board; and creating and maintaining the appropriate "tone at the top" to ensure that a "culture of integrity" applies to Capital Power's performance of functions pursuant to the Management and Operations Agreements.

        The primary responsibilities of the Board's Lead Director are to seek to ensure that appropriate structures are in place so the Board can function independently of management, to lead the process by which the Independent Directors Committee seeks to ensure that the Board represents and protects the interests of all Unitholders, and to act as Chair of the Board when non-independent directors (including the Chair) are conflicted, such as when the Board is discussing or determining issues related to the Manager's compensation and when non-arm's length issues are negotiated between Capital Power and the Partnership. The Lead Director is required to be independent as such term is defined under applicable Canadian securities law. The Lead Director position is filled by Mr. Allen Hagerman.

        The Board currently has four committees and one sub-committee:

        There is no executive committee or compensation committee (see "Compensation Discussion & Analysis").

        Written position descriptions for the Chairman of the Board, the Chair of each Board committee, the Lead Director and President of the General Partner, are contained in the various Terms of Reference attached to this AIF.

        The Terms of Reference for the Board of the General Partner are attached as Schedule B to this AIF.


Corporate Governance Committee

        The Corporate Governance Committee (GC) is currently composed of Allen Hagerman, Brian Vaasjo and Rod Wimer (Chair). Both Mr. Hagerman and Mr. Wimer are independent as such term is defined under applicable Canadian securities law and mandated by the GC's terms of reference. See "Board of Directors and Executive Officers".

        The GC operates under the Corporate Governance Committee Terms of Reference attached as Schedule C to this AIF.

        In general, the GC is tasked to assist the Board in developing the Partnership's approach to corporate governance issues, including, the response to applicable corporate governance guidelines and standards set by regulators or stock exchanges on which the Partnership's Units are listed. The GC is also responsible for assessing the effectiveness of the Partnership's system of corporate governance and, where necessary, making recommendations for improvement of the Partnership's system of corporate governance to ensure high standards of governance are achieved and maintained. The mandate of the GC includes: (i) monitoring and assessing the relationship between the Board and management, defining limits of management's responsibilities and seeking to ensure that there is a process in place to enable the Board to function independently of management; (ii) developing terms of reference or position descriptions for the Board, the Lead Director, President and any senior officers of the Partnership where necessary; (iii) reviewing potential conflicts for directors; (iv) seeking to ensure the

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ongoing adequacy, integrity and implementation of the strategic planning process; (v) reviewing and recommending to the Board rules and guidelines governing and regulating the affairs of the Board such as indemnification and compensation of directors; (vi) reviewing with the Manager its relevant succession plans, training programs, compensation policies and officer appointments; (vii) preparing and reviewing results and reporting to the Board on an annual assessment of Board and committee performance, including an evaluation of the competencies and skills that the Board as a whole should possess, and the basis of the evaluation and making recommendations to improve Board and Committee effectiveness; and (viii) reviewing periodically the performance and contribution of individual Board members.

        In addition, when required, the GC forms a sub-committee, composed entirely of Independent Directors, to serve as a Nominating Committee for the Board to assess potential candidates new for appointment as Independent Directors and make recommendations in respect thereof to the Board. Potential Independent Director candidates are assessed with a view to the critical skills they can bring to the Board and their alignment to the strategic plan of the Partnership. The GC, and ultimately the Board, undertakes a regular review of the current skills set of the Board as a whole to identify potential areas where a gap may exist and to anticipate new skills that may be required as the Partnership pursues its strategy. Subsequent to the Nominating Committee's recommendation of potential new candidates, the Board approves the slate of nominees for election which are presented for election annually by the shareholder of the General Partner.

        The GC is also tasked with the preparation of and review of results and subsequent reporting to the Board on the annual assessment of Board and committee performance, including an evaluation of the competencies and skills that the Board as a whole should possess, and the basis of the evaluation and including a periodic review of the performance and contribution of individual Board members. To assist in this review, questionnaires relating to Board and committee assessments are provided to each director for completion and these are reviewed by the GC. The GC uses the information in this evaluation to report to the Board.

        The GC also makes recommendations to improve Board and committee effectiveness. The GC undertakes a Board (including a peer review of individual members) and committee evaluation on an annual basis.


Audit Committee

        The Audit Committee (AC) is currently composed of Brian Felesky (Chair), Allen Hagerman (Vice Chair) and Francois Poirier. The Board has determined that all members of the AC are independent and financially literate as such terms are defined under applicable Canadian securities law and mandated under the AC's terms of reference. See "Board of Directors and Executive Officers". The Board based these determinations regarding financial literacy on the education and breadth and depth of experience of each AC member. See "Board of Directors—Directors" for a description of each member's relevant education and experience.

        The AC is directly responsible for overseeing the work of the external auditor engaged for the purpose of reviewing or attesting services, including the resolution of disagreements between management and the external auditor regarding financial reporting.

        The AC is responsible for assisting the Board in overseeing the integrity of the Partnership's financial statements, compliance with legal and regulatory requirements and ensuring the independence and performance of the Partnership's internal audit function and external auditors. The AC's Terms of Reference, are attached as Schedule D to this AIF.

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Independent Directors Committee

        The Independent Directors Committee (IDC) is currently composed of Allen Hagerman (Chair/Lead Director), Brian Felesky, Francois Poirier and Rod Wimer. All IDC members are independent as such term is defined under applicable Canadian securities law and mandated under the IDC's terms of reference. See "Board of Directors and Executive Officers".

        The IDC operates under the Independent Directors Committee Terms of Reference, attached as Schedule E to this AIF. The IDC is responsible for carrying out the obligations assigned to it by the Partnership Agreement, including reviewing, and, if thought appropriate, recommending for approval by the Board, all material transactions or agreements between the Partnership and Capital Power and its associates or affiliates.

        The IDC meets whenever deemed appropriate and necessary by the Independent Directors, without the presence of non-independent directors or management and generally at the end of all regular meetings of the Board. The IDC met 10 times in 2010 in connection with these regular meetings.

        Apart from their respective roles as directors of the General Partner, a description of the education and experience of Allen Hagerman (Chair/Lead Director), Brian Felesky, Francois Poirier and Rod Wimer, the members of the Independent Directors Committee, that is relevant to the performance of their responsibilities as independent directors and members of the Partnership's committees is found under "Board of Directors—Directors".


Other Committees

        The Partnership established two additional committees during 2010, the Special Committee and the Strategic Review Sub-Committee.

        The Special Committee of the Independent Directors of the Partnership, consisting of Allen Hagerman, Brian Felesky, Francois Poirier (as chair) and Rod Wimer, was formed to review and consider on behalf of the Partnership potential alternatives for the restructuring of the relationship between Capital Power and the Partnership. The Special Committee met 20 times in 2010.

        The Strategic Review Sub-Committee, consisting of Independent Director Francois Poirier and Stuart Lee, President of the General Partner and a senior officer of Capital Power, was created to act in an administrative capacity to the Board of Directors of the General Partner in the context of its strategic review process, and for that purpose, to lead the investigation of available strategic alternatives in the best interests of the Partnership.

        The Special Committee and the Strategic Review Sub-Committee both have written Terms of Reference, which due to the ongoing, sensitive nature of the strategic review have not been included as schedules.


Director Orientation and Continuing Education

        All Directors are provided with an orientation to the duties and obligations of directors and the business of the Partnership. Opportunities for meetings and discussions with senior management and other directors are also available and the details of the orientation of each new director are tailored to that Director's individual needs and areas of interest. In addition, a Corporate Governance Reference Manual (the CGR Manual) is provided to new Directors which helps familiarize new Directors with the Partnership (which is also updated, as appropriate and as necessary, for all existing Directors). The current CGR Manual covers a wide range of topics including: background information on the Partnership; information on Board structure; certain details on orientation and education; and key governance documents, policies, guidelines, codes and procedures. All Directors have participated with

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senior management at offsite strategic planning sessions at which all significant aspects of the Partnership's operations, opportunities and strategies are discussed. In addition the Board and the AC have attended a training session on International Financial Reporting Standards (IFRS) and the AC receives regular updates on the IFRS conversion projects.

        In 2010, as part of their continuing education, the Directors were given an in-depth presentation on IFRS on November 22, 2010.

        Management also periodically provides Directors with articles, papers and other materials relating to or addressing issues relevant to the Partnership, its business, and the various regulatory and legal regimes within which it operates, including on corporate governance matters. Directors are responsible for reviewing the materials provided and for generally keeping their knowledge of issues relevant to the Partnership current through the media and other public sources of information. The Partnership reimburses Directors for fifty percent of the cost of attending pre-approved educational conferences, industry symposia and other seminars (including direct out-of-pocket expenses related to travel) when in the Board's opinion, the Partnership will benefit from the Director's attendance at the seminar.

        The Partnership provides Directors with the opportunity to tour each of the various types of facilities and plants owned by the Partnership on a periodic basis.


Ethics Policy

        On April 27, 2010, the Partnership adopted a new Ethics Policy. Certification by all employees on the Ethics Policy was obtained in 2010. A copy of the Partnership's Ethics Policy can be obtained from the Partnership's website at www.capitalpowerincome.ca or under the Partnership's SEDAR profile at www.sedar.com. The Ethics Policy contemplates certification of all new personnel and periodic certification of existing personnel of the Manager and of the Independent Directors. The Manager has appointed an employee who is responsible for monitoring compliance with the Ethics Policy. Members of management are instructed to monitor compliance with the Ethics Policy and to report any compliance issues. The AC is mandated, to the extent it deems necessary or appropriate, to review and recommend to the Board for approval policy changes and program initiatives with respect to the implementation of the Ethics Policy and to obtain reports and report to the Board on the status and adequacy of the Partnership's efforts in seeking to ensure its businesses are conducted and its facilities are operated in an ethical, legally compliant and socially responsible manner, in accordance with the Ethics Policy.


External Auditor Service Fees

        The table below sets out amounts billed by KPMG LLP in its capacity as the Partnership's external auditor. KPMG LLP did not provide or bill for any tax services or other services outside its audit and audit related services in 2010 and 2009.

Fee Category ($000's)
  2010   2009(1)   Description of Fee Category

Audit Fees

  $ 826   $ 694   Aggregate fees billed for audit services.

Audit Related Fees(1)

  $ Nil   $ 57   Aggregate Partnership's fees billed by external auditor for the assurance and related services that are reasonably related to performance of the audit or review of the Partnership's financial statements and are not reported as Audit Fees.

All Other Fees(2)

  $ Nil   $ Nil    

Total

  $ 826   $ 751    

(1)
2009 figures have been restated to reflect fees on an accrual basis. Previously they were disclosed on a cash basis.

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(2)
Audit Related Fees are for services provided on financial instruments and due diligence comfort provided in respect of the Partnership's annual and certain interim management's discussion and analysis in connection with a prospectus filing.

(3)
All Other Fees are for services provided in respect of internal control over financial reporting and disclosure controls and procedures advisory matters.


Pre-Approval Policies and Procedures

        The AC's Terms of Reference provides that all non-audit services to be provided by the external auditor for the Partnership or its subsidiaries require pre-approval by the AC. The AC can delegate this pre-approval function to one or more members of the AC, provided that any exercise of the delegated pre-approval function must be reported to the AC at the next committee meeting following the pre-approval.


COMPENSATION DISCUSSION AND ANALYSIS

        The Partnership does not directly employ its executive officers. The General Partner has contracted for management and administrative services of the Partnership to be provided by the Manager. Accordingly, all of the executive officers of the General Partner serve in that capacity as nominees of the Manager in accordance with the Management and Operations Agreements and are therefore not compensated directly by the Partnership. The Manager, or its affiliates, employs substantially all of the staff carrying out the duties for the Partnership, including the Partnership's executive officers, in return for the payment of a fixed fee by the Partnership (the details of which are more particularly described herein under "Management of the Partnership" and "Interests of Management and Others in Material Transactions"). In addition, the Partnership pays incentive and other fees to the Manager that are based on the performance of the Partnership. See "Management of the Partnership" and "Interests of Management and Others in Material Transactions". The compensation paid to the General Partner's executive officers has no direct link to the fees paid to the Manager.

        The performance of the Partnership is an important element of Capital Power's overall corporate financial performance. Approximately 30% of the Partnership's Funds From Operations (FFO) is included in determining Capital Power's overall corporate financial performance for purposes of the performance measures applied under Capital Power's corporate short-term incentive plan (STIP) for the period December 31, 2010. The Total Recordable Injury Frequency Rate performance measure includes all reportable incidents and exposure hours of the 18 facilities that Capital Power employees operate on behalf of the Partnership.

        The General Partner is a direct wholly-owned subsidiary of CPI Investments. EPCOR owns all of the 51 voting, non-participating shares of CPI Investments and Capital Power owns all of the 49 voting, participating shares of CPI Investments. The Manager is controlled by Capital Power. Consequently, decisions relating to the compensation of the Partnership's executive officers are based on their respective roles, responsibilities and services within Capital Power as a whole and on Capital Power's overall performance relative to goals and targets established for Capital Power as a whole. Prior to July 2009, decisions relating to the compensation of the Partnership's executive officers were similarly based on their respective roles, responsibilities and services within EPCOR as a whole and on EPCOR's overall performance relative to goals and targets established for EPCOR as a whole.

        Executive compensation disclosure in this AIF is provided in respect of the Named Executive Officers (NEOs) of the Partnership (as such term is defined in Form 51-102F6—Statement of Executive Compensation of the Canadian Securities Administrators, each of whom is employed and compensated by Capital Power). In accordance with Form 51-102F6, the NEOs include the President of the General Partner (as Chief Executive Officer), the Chief Financial Officer of the General Partner and each of the three most highly compensated other executive officers of the General Partner, or individuals acting

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in a similar capacity. The three most highly compensated executive officers of the General Partner, other than the President and the Chief Financial Officer, have been determined by multiplying the amount of each of Capital Power's executive officer's total compensation from Capital Power by the proportion of their respective time generally spent on matters pertaining directly to the Partnership. On this basis, the NEOs of the Partnership for 2010 were:

        The NEOs' remuneration reported in the Summary Compensation Table and other tabular disclosure in this AIF represents the entire compensation paid to the Partnership's NEOs by Capital Power, (all compensation including salary, short-term and long-term incentives, pension and other benefits) based on their respective roles, responsibilities and services within Capital Power, as applicable, as a whole.


Capital Power Corporate Governance, Compensation & Nominating Committee

Composition

        The Corporate Governance, Compensation & Nominating Committee (the Capital Power CGC&N Committee) of the Capital Power Board of Directors approves, or recommends for approval, all remuneration to be awarded through Capital Power's executive compensation program to the Partnership's NEOs who are executives of Capital Power, including annual base salary, short-term and long-term incentive and executive allowances. Remuneration for the Partnership's NEOs who are not executives of Capital Power is determined under Capital Power's management compensation programs over which the Capital Power CGC&N Committee has oversight.

        The Capital Power CGC&N Committee is a committee of the Capital Power Board of Directors, composed of five members, each of whom, other than Mr. Cruickshank, is independent from Capital Power within the meaning of applicable Canadian securities laws. The members of the Capital Power CGC&N Committee are: Albrecht W.A. Bellstedt (Chair), Richard Cruickshank, Brian F. MacNeill, Robert Lawrence Phillips and Janice Rennie. As Chair of the Board, Don Lowry also attends Capital Power CGC&N Committee meetings in an ex-officio, non-voting capacity.

Mandate

        With respect to executive compensation, the Capital Power CGC&N Committee assists the Capital Power Board of Directors in fulfilling its responsibilities relating to the compensation, evaluation and succession of directors and employees of Capital Power, including the Partnership's NEOs and provides oversight of the Company's corporate governance and identifying conditions for Board nomination. The role of the Capital Power CGC&N Committee with respect to compensation is to:

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        The Capital Power CGC&N Committee has written Terms of Reference that establish its purpose, responsibilities, and membership.

        The Capital Power CGC&N Committee follows an objective process for determining compensation by holding "in camera" sessions at the end of each committee meeting, without management present.

        In November of 2010, the Capital Power CGC&N Committee engaged Hugessen Consulting to provide them with independent advice in respect of Capital Power directors' and executives' compensation and to advise the Capital Power CGC&N Committee, on a go-forward basis, on levels of compensation in the competitive market in which Capital Power operates and on other compensation matters.

        In its role as independent compensation consultant to the Capital Power CGC&N Committee, Hugessen Consulting will:

        The Partnership does not engage Hugessen Consulting as an executive compensation consultant and therefore no amounts were paid by the Partnership to Hugessen Consulting for executive compensation advice.

        Prior to that, Towers Watson acted as advisor to both Management and the Capital Power CGC&N Committee. The Partnership does not engage Towers Watson as an executive compensation consultant and therefore no amounts were paid by the Partnership to Towers Watson for executive compensation advice. Towers Watson continues to act as Management's consultant and will provide consulting advice and administrative support to Capital Power on compensation, pension and benefits matters.


Compensation Approval Process

        In accordance with its Terms of Reference the Capital Power CGC&N Committee carries out its responsibilities on an on-going basis throughout the year and has established a review process which includes the following matters:

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Compensation Philosophy and Objectives

        The Partnership's NEOs participate in the same direct compensation (salary, short and long term incentives), pension and benefit programs of Capital Power as other similarly positioned Capital Power Executives and management. The compensation of Capital Power's executives including the Partnership's NEOs, is influenced by a number of factors, including business strategy, organizational performance and governance. Capital Power's compensation philosophy aims to achieve the following objectives:

        These objectives have guided the development of a compensation model that includes base salary, short-term and long-term incentives. The compensation programs are designed to be market competitive with organizations in the Canadian energy and utility industries that are of a similar size and scope of operations to those of Capital Power. For executives, the primary focus is on performance related compensation (short-term and long-term incentives). For the Partnership's NEOs that are not executives of Capital Power, base salary may be more important. Capital Power's short-term incentive plan (STIP) is designed to reward executives for achievement of corporate and individual goals that have a one-year time horizon. Capital Power's long-term incentive plan (LTIP) is designed to align longer-term executive and stakeholder interests by focusing executives on Capital Power's longer-term strategic objectives and sustained value creation.

        In March 2011, the Capital Power CGC&N Committee approved a revised compensation philosophy, for executive positions where base salaries and short-term and long-term incentive opportunities will be targeted at the median of the market. The aggregate of base salary, short-term and long-term incentives will produce median compensation in the event of target performance of Capital Power and/or the individual, above median compensation in the event of superior performance of Capital Power and/or individual and below median compensation if performance falls short of expectations. This approach will better align Capital Power's executive compensation practices with those of their comparator companies. The performance of the Partnership is an important element of Capital Power's overall financial performance.

        Prior to this, Capital Power was targeting base salaries at below the median and short and long-term incentive opportunities at above the median of this market in order to encourage an entrepreneurial spirit on start-up.

Comparator Group

        For 2010 Capital Power's executive comparator group consisted of companies that met the following criteria:

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        As the 2010 comparator group was comprised of companies within a wide revenue range and included significantly larger organizations the data used to assess the competitiveness of executive compensation was size-adjusted to Capital Power's revenue using single-regression analysis.

        In 2010, the executive compensation comparator group comprised the following companies:

ATCO Ltd.   Nexen Inc.
Canadian Natural Resources Ltd.   Spectra Energy Corp.
Emera Inc.   Suncor Energy Inc.
Enbridge Inc.   Talisman Energy Inc.
Ensign Energy Services Inc.   TransAlta Corp.
Fortis Inc.   TransCanada Corp.
Husky Energy Inc.    

        For 2011 the comparator group selection criteria will be refined by narrowing the revenue scope to companies with revenues between $750 million and $10 billion. Raw percentile statistics for compensation data will be used, as opposed to regressed market data. Similar compensation levels are observed when market data from the 2010 comparator group is regressed to the market median revenue of the 2011 comparator group. Further refinements will be considered for 2012.

        For 2011 the executive compensation comparator group will comprise the following companies, with which Capital Power competes for talent and which the Capital Power CGC&N Committee believes to be an appropriate comparator group:

ATCO Ltd.   Pengrowth Energy Corp.
ARC Resources Ltd.   Penn West Energy Corp.
Emera Inc.   ShawCor Ltd.
Fortis Inc   Talisman Energy Inc.
Nexen Inc.   TransAlta Corp.
Pembina Pipeline Corp.   TransCanada Corp.

        Third party compensation surveys are used to compare base salary, short-term incentive and long-term incentive levels of Capital Power's executives to those of its comparators. Based on the analysis, compensation recommendations are formulated and brought forth to the Capital Power CGC&N Committee.

        A broader comparator group is used to benchmark senior management and professional positions.

        It should be noted that since the Partnership's NEOs' compensation is set based on their roles and responsibilities within Capital Power, the comparator group companies represent peers of Capital Power and are not chosen based on a comparison to the Partnership itself.

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Total Compensation Elements and Objectives

        The following table outlines the key elements of Capital Power's compensation program, including the objective and rationale for each compensation element and what each compensation element is intended to reward.

Compensation Element
  Objective and Rationale   What the Element Rewards

Base salary

  To provide a competitive base level of fixed compensation based on responsibilities, scope and market data.   Experience, expertise, knowledge and scope of responsibilities.

Short-term incentive program

 

To provide a component of compensation that is conditional on performance and rewards the achievement of annual targets that support Capital Power's strategic direction.

 

Achievement of short-term company objectives and/or individual performance goals.

Long-term incentive program

 

To provide a component of compensation that is conditional on sustained mid-term to long-term performance and aligns the interests of the executive officer with the interests of the shareholder through holdings of significant equity interests and to aid in long-term retention of executive officers.

 

Achievement of mid-term to long-term performance results resulting in share price increases.

Other compensation arrangements (and perquisites)

 

To provide a competitive total compensation package.

 

Scope of responsibilities.

Pension and other retirement benefits

 

To provide a competitive total compensation package that includes market competitive health benefits and retirement savings vehicles. Facilitates long-term financial security for executive officers and aids in retention.

 

Tenure.


Overview of Compensation Mix for NEOs in 2010

        The table below outlines the mix of base salary and compensation-at-risk for each of the Partnership's NEOs. The percentages shown for short and long-term incentive compensation assume achievement of target Capital Power performance levels. While variable compensation represents the greatest proportion of total compensation for several of the partnership's NEOs, the actual mix varies

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according to the NEO's role and level in Capital Power, their relative ability to influence short and long-term business results of Capital Power and market practices for comparable positions.

Executive
  Base Salary   Short-Term Incentive
Compensation
  Long-Term Incentive
Compensation
 

Stuart Anthony Lee

    45 %   23 %   32 %

Anthony Scozzafava

    66 %   17 %   17 %

Brian Tellef Vaasjo

    33 %   25 %   42 %

Graham Lloyd Brown

    47 %   24 %   29 %

David Hermanson

    65 %   19 %   16 %


Base Salary

        The Partnership does not have an annual base salary program for executive officers. The Partnership's NEOs are compensated under the Capital Power base salary program. Salaries are determined based on the responsibilities of each position, the executive's experience, expertise and knowledge when compared with market, individual performance and internal comparability and will generally align at a point below the median of the comparator group for executive positions with similar responsibilities to those of Capital Power. Base salaries for non-executive positions with Capital Power are targeted at the median of the comparator group for positions with similar responsibilities to those of Capital Power.


Short-Term Incentive Compensation

        The Partnership does not have a short-term incentive program (STIP) for executive officers. The Partnership's NEOs are compensated under Capital Power's corporate STIP.

The Corporate Short-Term Incentive Plan

        Capital Power believes that the corporate STIP should provide competitive bonuses that reflect corporate and individual performance. Corporate measures focus on corporate results and create joint accountability among the executives. Individual performance objectives allow for the differentiation of payouts based on individual contributions.

        In 2010, the Capital Power CGC&N Committee approved a new STIP. Performance measures and targets were chosen to better reflect Capital Power's business objectives and to improve the line of sight for all employees through better alignment to the financial reporting documentation and other activities considered critical for success.

Performance Measures

        Performance measures are approved by the Capital Power CGC&N Committee through the annual budgeting process based on Capital Power Corporation's performance. The only extent to which the compensation of the Capital Power executives who act as officers of the General Partner is affected by the Partnership's performance is to the extent that Capital Power Corporation performance measures incorporate the performance of the Partnership. At the end of the year, actual performance is measured against these pre-determined performance measures and the STIP pays out on the basis of achievement, within an expected range of performance: a minimum performance expectation (threshold), an expected result (target) and a plan maximum (stretch). The maximum payout under the plan will not exceed 2.0 times target. The following table shows Capital Power's performance measures applied for the period from January 1, 2010 to December 31, 2010 for the purposes of the STIP awards there under for the executive group.

Remainder of page left intentionally blank

Schedule III-59


Table of Contents

Performance Measure
  Weight   Target   Actual Result   Performance
Assessment

Financial

                 

—     Funds from Operations(1)

   
70

%

$250.0 million

 

$259.0 million

 

Above Target

Aggregated Safety

                 

—     Total Recordable Injury Frequency Rate (TRIF)(2)

   
15

%

1.20

 

1.48

 

Below Target

People Measure

                 

—     Organizational Design(3)

   
5

%

Complete the final two
phases of the
organizational design
project.
  
Incorporate
accountabilities and
deliverables into the
individual performance
measures for the CEO
and SVPs.

 

Completed the final
two phases of the
organizational
design project.
 
Incorporated
accountabilities and
deliverables into the
individual
performance
measures for the
CEO, SVPs,
Directors and Senior
Managers.

 

Above Target

—     Succession Planning(4)

   
5

%

Complete executive level
succession plans.
  
Create a developmental
plan for each high
potential employee.

 

Completed executive
and director level
succession plans.
  
Created a
developmental plan
for each high
potential employee.

 

Above Target

—     Turnover(5)

   
5

%

6.0%

 

6.0%

 

At Target


Notes:

(1)
The performance measure "Funds from Operations" represents cash provided by operating activities (GAAP defined term) less changes in operating working capital. Includes approximately 30.0% of the Partnership's funds from operations.

(2)
The performance measure "Total Recordable Injury Frequency Rate" represents the total number of employee fatalities and injuries resulting in lost time, restricted work duties or medical treatment per 200,000 work hours.

(3)
The performance measure "Organizational Design" represents the completion of an organizational design project which includes the final two phases, determining cross-functional accountabilities and authorities; and, aligning business deliverables to each stratum.

(4)
The performance measure "Succession Planning" represents the process for identifying and developing internal people with the potential to fill Senior Vice President and Director positions.

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(5)
The performance measure "Turnover" represents the number of permanent full-time employees who voluntarily leave the Partnership in 2010 divided by the actual number of active permanent full-time employees on December 31, 2009.

        Individual performance measures for the executive group include a combination of quantitative and qualitative goals with no pre-determined weightings. These goals are intended to align with the annual corporate objectives and reflect goals which have a reasonable likelihood of being achieved within the relevant year. If the goals are met, this would be considered target performance for purposes of the plan. Individual performance is rated on a scale from 1 to 5, with 1 being Unacceptable and 5 being Outstanding.

2010 STIP Targets

        The following table outlines the target incentive opportunity for each of the Partnership's NEOs for the fiscal year ended December 31, 2010:

Name
  Minimum   Target   Maximum  

Stuart Anthony Lee

    0 %   50 %   100 %

Anthony Scozzafava

    0 %   25 %   50 %

Brian Tellef Vaasjo

    0 %   75 %   150 %

Graham Lloyd Brown

    0 %   50 %   100 %

David Hermanson

    0 %   30 %   60 %

2010 STIP Payout Formula

        The target incentive opportunity for each position is a percentage of base salary and will generally align at a point above the median of the comparator group for executive positions with similar responsibilities to those of Capital Power.

        Payouts are based on the weighted-average of the combined corporate performance measures adjusted for individual performance results. The following formula is used to determine the final STIP award:

Base Salary   ×   Annual Incentive
Target Payout
  ×   Corporate Performance Result /
Individual Performance Modifier
  =   Annual STIP
Award

(e.g. $300,000)

 

 

 

(e.g. 50% of salary = $150,000)

 

 

 

(e.g. 150%)

 

 

 

(e.g. $225,000)

        The individual performance modifier is determined based on the following matrix and will be calculated using linear interpolation when corporate performance results fall between the threshold and target or target and stretch. The illustration above is based on "stretch" corporate performance results and an individual performance rating of "3".

 
  Individual Performance Rating  
Corporate Performance Result
  1   2   3   4   5  

Stretch

    0 %   75 %   150 %   175 %   200 %

Target

    0 %   50 %   100 %   125 %   150 %

Threshold

    0 %   0 %   50 %   75 %   100 %

Below Threshold

    0 %   0 %   0 %   0 %   0 %

Capital Power CGC&N Committee Oversight

        After considering and evaluating the performance results for the year, the Capital Power CGC&N Committee retains the discretion to adjust payouts under Capital Power short-term incentive plans to

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take into account factors affecting performance that are beyond the participants' control resulting in an outcome that would be unfair by either "over or underpaying" incentive or creating unintentional results.


Long-Term Incentive Compensation

        The Partnership does not have a long-term incentive program (LTIP) for executive officers. The Partnership's NEOs are compensated under Capital Power's LTIP. Capital Power has two LTIPs for its executives and employees, including the Partnership's NEOs; a LTIP for 2009 (the 2009 Plan) and a LTIP for the 2010 fiscal year and onward (the LTI Plan). The issuance of Units is not included as part of the LTIP due to the potential for a conflict of interest due to the Partnership's relationship with Capital Power. See "Business Risks—Conflict of interest risk related to the Partnership's relationship with Capital Power Corporation" in the MD&A.

The 2009 Plan

        The 2009 Plan is structured as a stock option plan providing for one-time only grants of options that replaced the value of outstanding 2006, 2007, 2008 and 2009 EPCOR phantom option grants held by individuals who became employees and executives of Capital Power. An aggregate of 2,183,100 stock options were granted to eligible participants of Capital Power including to individuals acting as officers of the Partnership on July 8, 2009. No further grants will be made under the 2009 Plan.

        Options granted under the 2009 Plan may be exercised, once vested, up to the expiry date of July 8 2016. The 2009 Plan also provides that, unless otherwise determined by the Capital Power Board of Directors, options will terminate within specified time periods set out in the 2009 Plan following the termination of employment of an eligible participant with the Company or affiliated entities. The options granted under the 2009 Plan were unvested at grant, with one third vesting on January 1 of each of 2010, 2011, and 2012.

        When used in this paragraph, the terms "insiders" and "security based compensation arrangement" have the meanings ascribed thereto in the TSX rules for this purpose. The number of Common Shares that may be (a) reserved for issuance to insiders pursuant to the 2009 Plan and under any other security based compensation arrangement of Capital Power and (b) issued within a one-year period to insiders pursuant to the 2009 Plan and under any other security based compensation arrangement of Capital Power, is in each case limited to 10% of the total number of outstanding Common Shares after giving effect to the exchange of the Exchangeable LP Units of Capital Power L.P.. The number of Common Shares which may be reserved for issuance to any one participant pursuant to the 2009 Plan and under any other security based compensation arrangement of Capital Power or options for services granted by Capital Power is limited to 5% of the total number of outstanding Common Shares after giving effect to the exchange of the Exchangeable LP Units of Capital Power L.P.

        If options granted under the 2009 Plan would otherwise expire during a trading black-out period or within 10 business days of the end of such period, the expiry date of the options will be extended to the tenth business day following the end of the black-out period.

        The interests of any participant under the 2009 Plan or in any option are not transferable, except to a spouse, minor child or grandchild or a trust or corporation controlled by the participant of which any combination of the participant and the foregoing are shareholders or beneficiaries. Upon any such permitted transfer, the transferred options shall be deemed for the purposes of the 2009 Plan to continue to be held by the participant. Upon death, the participant's legal personal representative shall receive the benefit of the option.

        The 2009 Plan may be amended with the approval of the Capital Power Board of Directors, in accordance with TSX requirements and, to the extent provided under the 2009 Plan, the approval of

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shareholders of Capital Power. The Capital Power Board of Directors has overall authority for interpreting, applying, amending and terminating the 2009 Plan.

The LTI Plan

        Under the LTI Plan, the Capital Power Corporation Board of Directors may in its discretion grant from time to time Capital Power stock options, performance share units (PSUs), restricted share units (RSUs) and stock appreciation rights (SARs) to employees and consultants, the "eligible participants", of Capital Power and its affiliated entities. An aggregate of 1,246,046 stock options and 152,801 PSUs were granted to eligible participants of Capital Power including to individuals acting as officers of the Partnership under the LTI Plan on March 9, 2010.

        Eligibility to receive grants of Capital Power stock options, PSUs, RSUs and SARs and grant guidelines are determined by the Capital Power Board of Directors, provided that non-employee directors of Capital Power are not eligible to participate in the LTI Plan. The CEO of Capital Power recommends to the Capital Power CGC&N Committee the actual recipients of such grants from among the eligible participants, the composition of the grants (as among options, PSUs, RSUs and SARs) and the actual grant size, taking into consideration such factors as their levels of responsibility, performance and market information. In determining the size and composition of the grants that the Capital Power CGC&N Committee recommends to the Capital Power Board of Directors, the Capital Power CGC&N Committee will consider their expected payout and the competitiveness of Capital Power's total compensation relative to Capital Power's comparator group in addition to the recommendation of Capital Power's CEO. The Capital Power CGC&N Committee will determine the grant size and composition to be recommended to the Capital Power Board of Directors in respect of the CEO of Capital Power. Capital Power intends to make new grants under the LTI Plan in subsequent years without taking prior grants into account when making such new grants.

        An aggregate of five million Capital Power Common Shares or approximately 6.4% of the number of outstanding Common Shares, after giving effect to the exchange of the Exchangeable LP Units of Capital Power L.P., have been reserved for issuance from treasury under the LTI Plan and the 2009 Plan. Capital Power may satisfy its obligations to deliver Common Shares under the LTI Plan by the issuance of Common Shares from treasury or by acquiring Common Shares in the market.

        When used in this paragraph, the terms "insiders" and "security based compensation arrangement" have the meanings ascribed thereto in the TSX rules for this purpose. The number of Common Shares that may be (a) reserved for issuance to insiders pursuant to the LTI Plan and under any other security based compensation arrangement of Capital Power and (b) issued within a one-year period to insiders pursuant to the LTI Plan and under any other security based compensation arrangement of Capital Power, is in each case limited to 10% of the total number of outstanding Common Shares after giving effect to the exchange of the Exchangeable LP Units of Capital Power L.P.. The number of Common Shares which may be reserved for issuance to any one participant pursuant to the LTI Plan and under any other security based compensation arrangement of Capital Power or options or rights granted for services granted by Capital Power is limited to 5% of the total number of outstanding Common Shares after giving effect to the exchange of the Exchangeable LP Units of Capital Power L.P..

        Options granted under the LTI Plan may be exercised during the period determined under the LTI Plan, which is generally seven years, or the shorter option period established by the Capital Power CGC&N Committee for any individual grant. The LTI Plan also provides that, unless otherwise determined by the Capital Power Board of Directors, options will terminate within specified time periods following the termination of employment of an eligible participant with the Company or affiliated entities. The exercise price for options granted under the LTI Plan is the closing price for Common Shares on the day prior to the grant. The exercise of options may, in the discretion of the Capital Power Board of Directors, be subject to vesting conditions, including specific time schedules for

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vesting and performance based conditions such as share price and financial results. The options granted on March 9, 2010 under the LTI Plan were unvested at grant, with one third vesting on March 9 of each of 2011, 2012 and 2013.

        Under the LTI Plan, the Capital Power Board of Directors also has the discretion to attach a SAR to an option when granted to an eligible participant or at a later date. Such SARs provide the holder with a right to receive an amount in cash or Common Shares equal to the difference between the option exercise price at the time of the grant and the closing price for a Common Share on the last trading day prior to exercise. The exercise of any such SARs will be subject to the same terms and conditions as the options to which they are attached. When SARs attached to an option are exercised, the related options are cancelled and the Common Shares underlying such cancelled options will, to the extent not used to satisfy stock settled SARs, no longer be available for issuance under the LTI Plan.

        The LTI Plan also permits eligible participants to receive grants of SARs that are not attached to options (Stand Alone SARs). Each Stand Alone SAR gives holders the right to receive an amount in cash or Common Shares equal to the difference between the market price of a Common Share at the time of grant and the market price of Common Shares at the time of exercise of the Stand Alone SAR. The "market price" used for this purpose is the simple average closing price of the Common Shares as traded on the stock exchange on which the highest aggregate volume of Common Shares have traded on each of the five trading days immediately preceding the grant or exercise date, as the case may be. Such amounts may also be payable at the election of the Company by the delivery of Common Shares. The exercise of Stand Alone SARs may also, at the discretion of the Capital Power Board of Directors, be subject to conditions similar to those that may be imposed on the exercise of stock options.

        Under the LTI Plan, eligible participants may be granted PSUs or RSUs, which represent the right to receive an equivalent number of Common Shares at a specified release date or an amount equal to the market price of such number of Common Shares on the release date (market price having the same meaning as in the case of Stand Alone SARs). The delivery of such Common Shares or payment of cash in respect of PSUs or RSUs may, at the discretion of the Capital Power Board of Directors, be subject to vesting requirements similar to those described above with respect to the exercisability of options and SARs, including such time or performance based conditions as may be established by the Capital Power Board of Directors. The PSUs granted on March 9, 2010 under the LTI Plan vest on January 1, 2013. Payout is based on relative total shareholder return over a three-year performance period.

        If incentives granted under the LTI Plan that are to be settled in newly issued Common Shares would otherwise expire during a trading black-out period or within 10 business days of the end of such period, the expiry date of the incentive will be extended to the tenth business day following the end of the black-out period.

        The interests of any participant under the LTI Plan or in any option, PSUs, RSUs or SAR are not transferable, subject to limited exceptions. An option may be transferred to a spouse, minor child or grandchild or a trust corporation controlled by the participant of which any combination of the participant and the foregoing are shareholders or beneficiaries. Upon any such permitted transfer, the transferred options shall be deemed for the purposes of the 2009 Plan to continue to be held by the participant. Upon death, the participant's legal personal representative shall receive the benefit of the option.

        The LTI Plan may be amended with the approval of the Capital Power Board of Directors, in accordance with TSX requirements and, to the extent provided under the LTI Plan, the approval of shareholders of Capital Power.

        The Capital Power Board of Directors has overall authority for interpreting, applying, amending and terminating the LTI Plan.

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Benefit and Pension Plans

        The Partnership does not have benefit or pension plans for executive officers. The Partnership's NEOs participate in Capital Power's benefit and pension plans. Capital Power's benefit and pension plans support the well-being of employees and facilitate retirement savings. The plans are reviewed periodically to determine whether they are competitive and whether they continue to meet Capital Power's business and human resources objectives.

Health and Welfare Benefits

        The benefit plans are designed to protect the health of employees and their dependents, and cover them in the event of death or disability. The Partnership's NEOs participate in the same benefits program as all other permanent employees of Capital Power. Capital Power provides Canadian based executives with an executive benefit allowance, paid on a semi-monthly basis, to offset employee costs under the plan.

Executive Business Allowance

        Executive officers of Capital Power, including the Partnership's NEOs, are provided with an annual taxable allowance that can be used to offset the cost of a variety of business related expenses including but not limited to memberships and other out-of-pocket expenses associated with performing the duties of the position.

Financial Planning Allowance

        Mr. Vaasjo is eligible to receive an annual financial planning allowance from Capital Power in an amount not exceeding $5,000. Other NEOs, who are also executives of Capital Power, are eligible to receive an annual financial planning allowance in an amount not to exceed $3,500.

Capital Accumulation Plan

        Under the voluntary Capital Accumulation Plan, all Canadian based non-bargaining unit employees of Capital Power may contribute up to 10% of their base salary towards a range of investment options, including Partnership Units. Employee contributions are matched to a maximum of 3% of base salary.


Pension Programs

        Canadian based employees participate in one of two registered pension plans: the Local Authorities Pension Plan (LAPP) and the Capital Power Pension Plan. The Capital Power Pension Plan includes a defined contribution component and, for certain employees who work in the Partnership's plants, a defined benefit component. There are no NEOs of the Partnership who participate in the defined benefit component of the Capital Power Pension Plan. In addition, Canadian management employees whose benefits under the Capital Power Pension Plan or the LAPP are limited due to the Tax Act maximum pension or contribution limits are eligible to participate in the Capital Power sponsored Supplemental Pension Plan.

        US based employees participate in the Capital Power 401(k) plan.

LAPP Plan

        The LAPP is a contributory, defined benefit, best average earnings pension plan that is governed by the Public Sector Pension Plans Act (Alberta). The LAPP is a multi-employer pension plan that covers approximately 140,000 active members as at December 31, 2010 who are employed by Alberta municipalities, hospitals and other public entities. Mr. Lee, Mr. Scozzafava and Mr. Vaasjo participate in the LAPP.

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        Benefits payable under the LAPP are based on the average of the best five consecutive years of pensionable earnings and years of service. Pensionable earnings are equal to base salary plus actual bonus, up to a maximum of 20% of base salary (effective January 1, 2004). Pensionable earnings are limited for each year of service after 1991 to the earnings which provide the maximum annual accrual under the Tax Act.

        Subject to Tax Act limits, the benefit formula under the LAPP is 1.4% of the average of the best five consecutive year's annual pensionable earnings up to the average Year's Maximum Pensionable Earnings (YMPE) under the Canada Pension Plan plus 2% of the average of the best five consecutive year's annual pensionable earnings in excess of the five year average YMPE. The benefit formula is multiplied by years of service up to a maximum of 35 years.

        Employee and employer contribution rates under the LAPP are set out in the plan rules and are adjusted from time to time by the LAPP Board of Trustees based on recommendations from the plan's actuary. In 2010, members were required to contribute 8.06% up to the YMPE plus 11.53% of pensionable earnings in excess of the YMPE, and employers contributed 9.06% up to the YMPE and 12.53% of pensionable earnings in excess of the YMPE.

        The pension payable under the LAPP is reduced by 3% for each year that the combination of the individual's age and years of service is less than 85 or for each year the individual is younger than 65, whichever provides the lower reduction. No pension is payable if a participant has not completed two years of service.

        The pension payable is indexed annually to 60% of the increase in the Alberta consumer price index.

The Capital Power Defined Contribution (DC) Plan

        Contributions to the Capital Power DC Plan are made based on pensionable earnings subject to the annual limits imposed under the Tax Act. Specifically, members are required to contribute 5% of pensionable earnings and Capital Power contributes either 5%, 6.5%, or 8% of pensionable earnings depending on the member's length of service.

        Mr. Brown participates in the Capital Power DC Plan.

        In late 2010, the Capital Power DC Plan was amended to allow executive members the option to suspend their membership. Executive members who elect to suspend their membership will not receive any company contributions and cannot make employee contributions to the Capital Power DC Plan for the duration of the suspension. Executive members have the right to lift the suspension and thereby resume making employee contributions, at which point the company contributions will resume, for future service only from the date that the suspension is lifted. In addition, executive members have the option to elect to irrevocably transfer their account balance in the Capital Power Plan to a locked-in retirement savings vehicle.

        Should an executive member choose to suspend their membership in the Capital Power DC Plan, Capital Power will provide a payment to the executive member equivalent to the amount that would have been paid into the executive member's plan had he or she not chosen to suspend their membership in the pension plan. Any such payment does not become part of the executive's base salary and is subject to all applicable taxes and payroll withholding requirements.

Supplemental Pension Plan (SPP)

        Capital Power has established a non-registered, unfunded and non-contributory SPP that provides benefits that cannot be provided under the Capital Power registered pension plan or, if applicable, the LAPP due to the Tax Act maximum pension or contribution limits.

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        All of the partnership's NEOs, with the exception of Mr. Hermanson, participate in the SPP.

        The pensionable earnings defined under the SPP includes base salary and target bonus. For employees who transferred from EPCOR in July of 2009, the Capital Power SPP has the same provisions as the EPCOR Utilities Inc. Supplemental Pension Plan. Specifically, the SPP provides a defined benefit pension equal to 2% of the average pensionable earnings in excess of an earnings threshold multiplied by service after January 1, 2000. The SPP has the same early retirement and indexing provisions as the LAPP. For new hires after July 2009 the Capital Power SPP provides benefits on a defined contribution basis that are in excess of the Tax Act maximum contribution limits. For employees who transferred from EPCOR, Capital Power assumed all obligations from EPCOR relating to the entitlements accrued under the EPCOR Utilities Inc. Supplemental Pension Plan.

        Executives who elect to withdraw from the Company DC Pension Plan are still eligible to participate in the SPP for earnings above the Tax Act maximum pension or contribution limits.

The Capital Power 401(k) Plan

        Capital Power's US based employees including Mr. Hermanson participate in the Capital Power 401(k) Plan.

        Members are permitted to make pre-tax elective contributions of up to 100% (less applicable tax withholdings) of eligible compensation (maximum of US$22,000 in 2009, including up to $5,500 in catch-up contributions for employees at least age 50). After tax contributions are not permitted. Eligible compensation includes total salary and wages during the plan year as reported on the W-2, including pre-tax contributions to the Plan. Annual compensation in excess of US$245,000, as adjusted for cost of living increases, is not included.

        Capital Power matches employee contributions equal to 100% of the member's pre-tax contributions up to 5% of compensation plus Capital Power has the option to make additional matching contribution equal to 2% of the first 2% the member elects to defer. Each year Capital Power had the option to make an additional matching contribution and/or additional employer contribution on behalf of each eligible participant in amounts determined by Capital Power.

        Interest credited on 401(k) accounts reflects the rate of return on investment options selected by the participant.

        Mr. Brown participated in the Capital Power 401(k) from January 1, 2006 to December 31, 2009 and commenced participation in the Capital Power DC Plan on January 1, 2010.


EXECUTIVE COMPENSATION

Summary Compensation Table

        The following table provides a summary of compensation for each of the Partnership's NEOs for the years ended December 31, 2010, 2009 and 2008. The NEOs' remuneration reported in the Summary Compensation Table represents the entire compensation paid to the Partnership's NEOs by Capital Power or EPCOR, as applicable, (all compensation including salary, short-term and long-term incentives, pension and other benefits) based on their respective roles, responsibilities and services within Capital Power or EPCOR, as applicable, as a whole.

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Table of Contents

 
   
   
   
   
  Non-Equity Incentive
Plan Compensation
   
   
   
 
Name and Principal Position
  Year   Salary(1)(7)
($)
  Share Based
Awards(2)(7)
($)
  Option
Based
Awards(3)(7)
($)
  Annual
Incentive
Plans(4)(7)
($)
  Long-Term
Incentive
Plans(5)(7)
($)
  Pension Value(6)(7)
($)
  All Other
Compensation(7)
($)
  Total
Compensation(7)
($)
 

Stuart Anthony Lee

    2010   $ 338,269   $ 112,000   $ 112,000   $ 226,474   $ 0   $ 90,672   $ 43,309 (18) $ 922,725  
 

President of the General

    2009   $ 276,385       $ 152,144   $ 290,000   $ 0   $ 161,902   $ 95,165 (19) $ 975,596  
 

Partner(8)(10)(11)

    2008   $ 235,231       $ 0   $ 136,000   $ 4,427   $ 51,573   $ 31,822 (20) $ 459,053  

Anthony Scozzafava

   
2010
 
$

253,364
 
$

30,726
 
$

30,726
 
$

101,772
 
$

0
 
$

45,591
 
$

10,000
 
$

472,180
 
 

Chief Financial Officer of

    2009   $ 243,892       $ 95,604   $ 106,552   $ 0   $ 37,663   $ 9,438   $ 493,149  
 

the General Partner(8)(11)

    2008   $ 234,177       $ 0   $ 97,000   $ 931   $ 51,678   $ 8,333   $ 392,119  

Brian Tellef Vaasjo

   
2010
 
$

679,231
 
$

406,250
 
$

406,250
 
$

679,000
 
$

0
 
$

246,466
 
$

56,042

(21)

$

2,473,240
 
 

Chairman of the General

    2009   $ 529,923       $ 610,632   $ 843,000   $ 0   $ 788,003   $ 113,936 (22) $ 2,885,494  
 

Partner(9)(10)(11)

    2008   $ 422,692       $ 0   $ 341,000   $ 6,042   $ 122,903   $ 42,822 (23) $ 935,459  

Graham Lloyd Brown

   
2010
 
$

259,615
 
$

74,999
 
$

74,999
 
$

137,500

(17)

$

0
 
$

47,728
 
$

39,398

(24)

$

634,240
 
 

SVP, Operations of Capital

    2009   $ 277,699       $ 156,770   $ 204,414   $ 0   $ 19,585   $ 75,532 (25) $ 734,000  
 

Power(9)(10)(11)(13)(14)(15)

    2008   $ 228,435       $ 0   $ 199,342   $ 0   $ 12,259   $ 10,660 (26) $ 450,696  

David Hermanson

   
2010
 
$

218,530
 
$

25,750
 
$

25,750
 
$

63,886
 
$

0
 
$

13,237
 
$

729
 
$

347,883
 
 

VP, US Operations of Capital

    2009   $ 246,909       $ 79,670   $ 104,862   $ 0   $ 9,528   $ 19,938   $ 460,907  
 

Power(9)(12)(14)(15)(16)

    2008   $ 213,200       $ 0   $ 63,960   $ 0   $ 7,950   $ 0   $ 285,110  

Notes:

(1)
See "Compensation Discussion and Analysis—Base Salary".

(2)
2010 share based awards represent the grant date expected value of the Capital Power PSU grant for 2010 under the LTI Plan. Payout is based on how the Capital Power's total shareholder return performs relative to the total shareholder return of the companies in the Capital Power performance peer group.

(3)
2010 option based awards represent the expected value of the Capital Power stock option grant for 2010 under the LTI Plan. 2009 option based awards represent the expected value of the Capital Power stock option grant for 2009 as well as the replacement for the outstanding 2006, 2007 and 2008 EPCOR grants under the 2009 Plan.

(4)
See "Compensation Discussion and Analysis—Short-Term Incentive Compensation". Represents short-term incentive award earned for the stated year's performance and paid in the subsequent year.

(5)
See "Compensation Discussion and Analysis—Long-Term Compensation". For 2008, reflects long-term incentive payment for the 4-year performance cycle from 2005 to 2008 and paid by EPCOR in 2009.

(6)
See "Compensation Discussion and Analysis—Benefit and Pension Plans". 2009 values reflect a one time increase in pensionable earnings as a result of the transfer of the NEOs from EPCOR to Capital Power.

(7)
Represents the total annual salary, share-based awards, option-based awards, annual incentive compensation, long-term incentive compensation, annual compensatory pension value or other annual compensation value, as applicable, paid to the Partnership's NEOs by Capital Power, or EPCOR, as applicable.

(8)
Mr. Lee and Mr. Scozzafava are designated NEOs based upon their respective positions as President and Chief Financial Officer of the General Partner.

(9)
The approximate percentages of time that the NEOs spent rendering services to the Partnership relative to their services to Capital Power or EPCOR, as applicable, were as follows: Mr. Vaasjo—20% in 2010, 15% in 2009, 35% in 2008; Mr. Brown—60% in 2010, 75% in 2009, 95% in 2008; Mr. Hermanson—90% in both 2010 and 2009, 100% in 2008. A change in the percentage of time a NEO allocates to the Partnership would not affect the NEOs' compensation from Capital Power.

(10)
NEOs who are directors of the General Partner do not and did not receive any incremental income from Capital Power or EPCOR or the Partnership for their roles as directors of the General Partner.

(11)
Canadian based NEOs. See "Compensation Discussion and Analysis—Benefit and Pension Plans".

(12)
US based NEOs. See "Compensation Discussion and Analysis—Benefit and Pension Plans".

(13)
Mr. Brown retired from Capital Power in January 2011.

(14)
For 2008, converted to Canadian dollars using an average conversion rate of 1.066 Canadian/US with the average rate based on 252 days of data provided by the Bank of Canada.

(15)
For 2009, converted to Canadian dollars using an average conversion rate of 1.142 Canadian/US with the average rate based on 251 days of data provided by the Bank of Canada.

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(16)
For 2010, converted to Canadian dollars using an average conversion rate of 1.030 Canadian/US with the average rate based on 251 days of data provided by the Bank of Canada.

(17)
Mr. Brown's STIP award was paid out at target following his retirement.

(18)
Includes an executive benefit allowance of $14,000 and an executive business allowance of $15,000.

(19)
Includes a vacation payout of $56,385.

(20)
Includes an executive benefit allowance of $13,404, an executive business allowance of $9,981 and a matching contribution into the EPCOR savings plan of $7,507.

(21)
Includes an executive benefit allowance of $15,474, an executive business allowance of $15,000 and employer contributions to the Capital Power capital accumulation plan of $20,377.

(22)
Includes a vacation payout of $64,866.

(23)
Includes an executive benefit allowance of $13,790, an executive business allowance of $14,971 and a matching contribution into the EPCOR savings plan of $12,681.

(24)
Includes an executive benefit allowance of $13,462 and an executive business allowance of $14,423.

(25)
Includes a relocation allowance of $47,582 and an executive business allowance of $27,122.

(26)
Includes an executive business allowance of $10,660.

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Long-Term Incentive Plan

        The 2010 grant under the LTI Plan consisted of Stock Options and Performance Share Units, with 50% of the target value coming from each vehicle.

        Options granted in 2010 vest in equal amounts on March 9 in each of 2011, 2012 and 2013 and have a seven-year term.

        PSUs granted in 2010 vest on January 1, 2013 based on Capital Power's total shareholder return (share price plus dividend equivalents) relative to the total shareholder return of the companies in a performance peer group. Relative TSR was selected as the performance measure as it complements the absolute performance focus of stock options and is a holistic measure that encompasses share price performance plus dividends. Upon vesting, PSUs will be settled in cash.

        The performance peer group consists of organizations with similar business characteristics (e.g., power generation/transmission/utility companies, high dividend yield), reflects companies that compete directly for capital with Capital Power and are consistent with the executive compensation comparator group. The composition of Capital Power's performance peer group will be reviewed annually by third party consultants and the Capital Power CGC&N Committee for continued relevance. In 2010, the performance peer group comprised the following companies:

Algonquin Power & Utilities Corp.   Enbridge Inc.
Atlantic Power Corp.   Fortis Inc.
Brookfield Renewable Power Inc.   Northland Power Inc.
Canadian Utilities Ltd.   TransAlta Corp.
Emera Inc.   TransCanada Corp.

        A vesting range with a floor of 50% of target for minimum performance and a cap of 150% of target for maximum performance was established as Capital Power does not have a lengthy trading history and felt a conservative approach was appropriate. Accordingly;

        Vesting is interpolated on a straight-line basis between threshold and target and between target and maximum.

        The performance criteria and vesting range will be reviewed in 2013 for continued relevance.

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        The following table sets forth the information regarding the options and PSUs that were granted to the Partnership's NEOs under the LTI Plan during the fiscal year ended December 31, 2010:

 
   
   
   
   
  Share-based Awards  
 
  Option-based Awards  
 
   
  Market or
payment
value of
share-based
awards that
have not
vested(4)
($)
 
Name
  Number of
securities
underlying
unexercised
options
(#)
  Option
exercise
price
($)
  Option expiration
date(1)
  Value of
unexercised
in-the-money
options(2)
($)
  Number of
shares or
units that
have not
vested(3)
(#)
 

Stuart Anthony Lee

    47,160     22.50     March 9, 2017   $ 54,234     6,024   $ 142,465  

Anthony Scozzafava

    12,938     22.50     March 9, 2017   $ 14,879     1,653   $ 39,096  

Brian Tellef Vaasjo

    171,060     22.50     March 9, 2017   $ 196,719     21,850   $ 516,746  

Graham Lloyd Brown

    31,580     22.50     March 9, 2017     36,317     4,034   $ 95,412  

David Hermanson

    12,381     22.50     March 9, 2017   $ 14,238     1,581   $ 37,396  

Notes:

(1)
The date of grant of the options and the PSUs was March 9, 2010.

(2)
The difference between the closing share price of Capital Power Corporation common shares on the TSX on December 31, 2010 of $23.65 per share and the option exercise price, times the number of outstanding vested and unvested stock options.

(3)
Includes reinvested dividends.

(4)
The closing share price of Capital Power Corporation common shares on the TSX on December 31, 2010 of $23.65 per share multiplied by 100% of the number of PSUs that have not vested. The values noted in this column represent the target payout value.

Outstanding Share Based Awards and Option based Awards

        The following table sets forth the aggregate value of all option based awards, share based awards and non-equity incentive plan compensation previously made to the Partnership's NEOs that vested during the fiscal year ended December 31, 2010:

Pension Plan Tables

Name
  Option-based awards—
Value vested during
the year(1)
($)
  Share-based awards—
Value vested during
the year
($)
  Non-equity incentive
plan compensation—
Value vested during
the year
($)

Stuart Anthony Lee

  $ 12,826   $ 0   N/A

Anthony Scozzafava

  $ 8,060   $ 0   N/A

Brian Tellef Vaasjo

  $ 51,480   $ 0   N/A

Graham Lloyd Brown

  $ 13,216   $ 0   N/A

David Hermanson

  $ 6,716   $ 0   N/A

Notes:

(1)
The difference between the closing share price of Capital Power Corporation common shares on the TSX on December 31, 2010 of $23.65 per share and the weighted average option exercise price, times the number of stock options that vested during the year.

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Pension Plan Tables

        The Defined Benefits Plan Table set forth below provides a reconciliation of the accrued obligation for the Partnership's NEOs who have defined benefit entitlements. In particular, the compensatory change reflects the Capital Power SPP employer current service cost, any change in the Capital Power SPP obligation due to the actual increase in compensation during the period being different than expected, any change in the Capital Power SPP obligation due to plan changes, and, if applicable, the employer contributions to the LAPP. The actual increase in compensation may deviate from the expected increase used in the actuarial assumptions. The actual increase will vary between the Partnership's NEOs and will vary from year to year.

        The Defined Contribution Plan Table set forth below provides a reconciliation of accumulated values. In particular, the compensatory change for the Partnership's Canadian based NEOs who participate in the Capital Power DC Plan equals the employer contribution made in respect of the Partnership's NEOs.

Defined Benefits Plan Table

 
   
  Annual Benefits
Payable
($)
  Accrued
Obligation at
January 1,
2010(7)(8)
($)
(d)
   
  2010
Non-
Compensatory
Changes(8)
($)
(f)
  Accrued
Obligation at
December 31,
2010(7)(8)
($)
(g)
 
 
  Number of
Years Credited
Service
(#)
(b)
  2010
Compensatory
Changes(7)
($)
(e)
 
Name(a)
  At year end(5)
(c1)
  At age 65(6)
(c2)
 

Stuart Anthony Lee

    7.4452 (1)   49,256     171,649     340,601     90,672     117,018     532,527  

Anthony Scozzafava

    9.4589 (1)   49,723     160,989     239,468     45,591     82,915     352,210  

Brian Tellef Vaasjo

    12.5833 (2)(3)   177,589     330,424     1,813,996     246,466     440,317     2,485,015  

Graham Lloyd Brown

    2.3041 (4)   3,203     13,051     34,720     36,249     16,012     86,981  

Notes:

(1)
Credited service under LAPP and SPP.

(2)
Credited service in respect of LAPP as at December 31, 2010.

(3)
Credited service under SPP is 11 years.

(4)
Credited service under SPP.

(5)
Accrued Defined Benefit pension under the SPP and, if applicable, the LAPP as at December 31, 2010 and payable at normal retirement age of 65. Reflects highest average earnings and credited service as at December 31, 2010.

(6)
Benefits payable on retirement at age 65, assuming continued service accrual to age 65 and highest average earnings as at December 31, 2010 remain unchanged.

(7)
The accrued benefit obligation and the service cost were calculated using the projected unit credit cost method.

(8)
Reflects SPP only. LAPP has been valued on a defined contribution basis; therefore, $15,764 in employer contributions to LAPP has been included in column (e) compensatory changes only, with the exception of Mr. Brown who does not participate in the LAPP. As a result, where applicable, columns (d), (e) and (f) do not sum up to column (g).

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Defined Contribution Plan Table

Name
  Accumulated Value at
December 31, 2009
($)
  2010
Compensatory
Changes
($)
  2010 Non-
Compensatory
Changes
($)
  Accumulated Value at
December 31, 2010
($)
 

Graham Lloyd Brown

    19,796     11,479     13,942     45,217  

401(k) Pension Plan Table

Name
  Accumulated Value at
December 31, 2009
(US$)
  2010
Compensatory
Changes
(US$)
  2010 Non-
Compensatory
Changes
(US$)
  Accumulated Value at
December 31, 2010
(US$)
 

Graham Lloyd Brown

    104,774         7,848     112,622  

David Hermanson

    246,949     12,852     51,005     310,806  


INDEBTEDNESS OF DIRECTORS AND EXECUTIVE OFFICERS

        No director or executive officer of the General Partner was, as of December 31, 2010 or is, as of the date hereof, indebted to the Partnership, the General Partner or any of its subsidiaries.


COMPENSATION OF THE BOARD OF DIRECTORS

        The directors' compensation program is designed to attract and retain the most qualified individuals to serve on the Board. In consideration for serving on the Board for 2010, each director who was not an executive officer or employee of the General Partner or Capital Power was compensated by the Partnership as indicated below:

Type of Fee
  Amount

Board Chair Retainer

  Nil

Director Retainer

  $35,000/year

Special Committee Chair Retainer(1)

  $50,000/year

Audit Committee Chair Retainer

  $10,000/year

Governance Committee Chair Retainer

  $5,000/year

Independent Directors Committee Chair Retainer

  $24,000/year

Special Committee Member Retainer(1)

  $35,000/year

Audit Committee Member Retainer

  Nil

Other Committee Member Retainer

  Nil

Board Meeting Attendance Fee(2)

  $1,600/meeting

Committee Chair Attendance Fee

  $2,600/meeting

Committee Member Attendance Fee

  $1,600/meeting

Unit Retainer(3)

  $25,000/year

Travel Allowance(4)

  $1,600/trip

Material and/or Complex Non-Arms Length Transaction(5)

  Fixed retainer of up to $15,000 plus meeting fees, the sum of which is not to exceed $30,000/non-arms length transaction without Board approval

Special Assignment Fee(5)

  $1,600/day

Notes:

(1)
The Special Committee retainer was split into two payments (50% each)—the first payment was made in Q3 of 2010 and the second payment will be made in 2011.

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(2)
This fee is reduced by 50% for any telephonic meeting of one hour or less in duration.

(3)
Although all Independent Directors receive the Unit Retainer, non-resident directors are ineligible to hold Partnership Units so non-resident directors are not required to purchase units with their annual Unit Retainer. See "Compensation of the Board of Directors—Unit Ownership by Directors".

(4)
In circumstances in which (i) a Director must travel for four hours or more from his or her place of residence to or from a Board or Committee meeting or (ii) is required to spend a night or more away from home, then a travel allowance is paid in addition to the regular meeting fee.

(5)
For material and/or complex transactions, the Board has authorized an additional cash retainer in addition to necessary meeting fees. For less material and/or complex transactions, the additional compensation payable to directors will be confined to meeting fees. In the case where an Independent Director is asked to perform a special assignment on behalf of the Partnership (such as recruitment of new directors or because of their unique qualifications), he/she will also be paid a daily rate equivalent to a meeting fee.


Summary of Directors' Compensation for the Fiscal Year 2010

        The table below details the compensation provided to directors of the General Partner who are not NEOs in the fiscal year ending December 31, 2010:

Name(1)
  Fees
Earned
  Share-
Based
Awards(9)
  Option-
Based
Awards
  Non-Equity
Incentive Plan
Compensation
  Pension
Value
  All Other
Compensation
  Total  

Brian A. Felesky

  $ 132,600 (5) $ 25,000                   $ 157,600  

Allen R. Hagerman

  $ 165,500 (6) $ 25,000               $ 1,600 (10) $ 192,100  

Francois L. Poirier

  $ 185,700 (7) $ 25,000               $ 14,400 (10) $ 225,100  

Rodney D. Wimer(2)(3)

  $ 128,500 (8)   (3)             $ 9,600 (10) $ 138,100  

James N. Oosterbaan(4)

                             

Notes:

(1)
Does not include Stuart A. Lee, Brian T. Vaasjo or Graham L. Brown, as such directors are also NEOs and their total compensation is reflected under "Summary Compensation Table" in this AIF.

(2)
Canadian equivalent paid in US$ when paid.

(3)
Non-resident directors (who are not eligible to hold Units) receive a long-term compensation award, accruing each year and paid in cash when the director leaves the Board, equal to the increase in market value of the number of Units that would have been purchased with the long-term compensation award of $25,000 if such amount had been used to purchase Units. As at December 31, 2010, Mr. Wimer would have been entitled to receive $170,004 pursuant to this award.

(4)
These individuals are senior officers of Capital Power and are compensated as officers of Capital Power by Capital Power through its executive compensation program. See "Executive Compensation". As part of their employment, these individuals have been asked to sit on the Board of the Partnership. Capital Power attributes none of their compensation to services provided to the Partnership. The individuals do not receive any incremental compensation from the Partnership for their roles as directors of the Partnership.

(5)
Includes $35,000 director retainer, $5,000 Audit Committee Chair retainer, $17,500 Special Committee Member retainer, $20,800 in board meeting attendance fees, $22,300 in committee meeting attendance fees and $28,800 in special meeting attendance fees. Includes $3,200

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(6)
Includes $35,000 director retainer, $5,000 Audit Committee Chair retainer, $24,000 Independent Committee Chair retainer, $17,500 Special Committee Member retainer, $20,800 in board meeting attendance fees, $29,200 in committee meeting attendance fees and $29,800 in special meeting attendance fees. Includes $5,200 committee meeting attendance fees that will be paid in Q1 of 2011 for two Independent Directors meetings held on December 17, 2010 and December 30, 2010.

(7)
Includes $35,000 director retainer, $50,000 Special Committee Chair retainer, $12,500 Strategic Review Committee retainer, $20,800 in board meeting attendance fees, $18,400 in committee meeting attendance fees and $45,800 in special meeting attendance fees. Includes $3,200 committee meeting attendance fees that will be paid in Q1 of 2011 for two Independent Directors meetings held on December 17, 2010 and December 30, 2010.

(8)
Includes $35,000 director retainer, $5,000 Governance Committee Chair retainer, $17,500 Special Committee Member retainer $20,800 in board meeting attendance fees, $20,600 in committee meeting attendance fees and $28,000 in special meeting attendance fees. Includes US$3,200 committee meeting attendance fees will be paid in Q1 of 2011 for two Independent Directors meetings held on December 17, 2010 and December 30, 2010.

(9)
Represents the annual equity retainer paid to independent Canadian directors in cash. The independent Canadian directors are required to invest the sum given to them in Units. See "Compensation of the Board of Directors—Unit Ownership by Directors".

(10)
Travel Allowance & Special Assignment.

        Compensation for Independent Directors is competitive and market-based, when independently benchmarked relative to a defined industry peer group. Compensation is revisited periodically by an independent expert who seeks to ensure that director compensation remains competitive and the principles used for determining compensation reflect current industry practices. Compensation is recommended by the Board's Governance Committee for approval by the Board.

        The Independent Directors receive a combination of cash retainer, annual unit retainer or cash equivalent, and meeting fees. In addition, given that the Partnership's business model incorporates growth through non-arms length transactions, an additional component of compensation for the Independent Directors is provided when these transactions occur so as to recognize the materiality and/or complexity of the transaction and the time required by the Independent Directors to discharge their fiduciary responsibility.


Unit Ownership by Directors

        The General Partner's Board has determined that ownership of Units by the independent directors is a positive step in helping members to align their interests with those of the Unitholders. The Board has adopted a policy guideline that requires independent Canadian directors to invest the sum given to them as an annual unit cash retainer in Units. Non-resident directors that are ineligible to hold Units receive a long-term compensation award, accruing each year and paid in cash when the director leaves the Board, equal to the market value of the number of Units that would have been purchased with the long-term compensation award if such amount had been used to purchase Units. See "Compensation of the Board of Directors".

        The Partnership does not issue and has not issued any unit or stock options in the Partnership or General Partner.

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PERFORMANCE GRAPH

        The following graph compares the annual change over the past five years in the cumulative total Unitholder return on the Units of the Partnership with the cumulative total return on the S&P/TSX Composite Index, assuming a $100 investment on December 31, 2005 and reinvestment of distributions.

GRAPHIC

 
  December 31,
2005
  December 31,
2006
  December 31,
2007
  December 31,
2008
  December 31,
2009
  December 31,
2010
 

CPA.UN

  $ 100   $ 82   $ 78   $ 65   $ 64   $ 80  

S&P/TSX Composite Index

  $ 100   $ 117   $ 129   $ 86   $ 117   $ 137  

        Over the five-year period ending December 31, 2010, cumulative total Unitholder return on the Units of the Partnership decreased by approximately 20%. Total direct compensation for the NEOs over the same period increased. For the purposes of comparison over the period, total direct compensation for the NEOs includes base salary, annual incentive payment and the value of the annual equity award.

        The NEOs are not compensated by the Partnership, but as employees or officers of Capital Power. Consequently, decisions relating to their compensation are based on their respective roles, responsibilities and services within Capital Power as a whole and on Capital Power's overall performance relative to goals and targets established for Capital Power as a whole. Therefore, it is not anticipated there will be a direct correlation between the cumulative total unitholder return relative to the cumulative total return on the S&P/TSX Composite Index and executive compensation levels over a given period.

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CONFLICTS OF INTEREST

General

        As a result of Capital Power's relationship with the Partnership, certain conflicts of interest could arise from time to time in which the Partnership's interests are not aligned with those of Capital Power. For example the strategic review may result in a situation in which the same potential alternatives do not serve the best interests of both parties equally.

        Capital Power is indirectly, the principal Unitholder of the Partnership. The General Partner is controlled by Capital Power, and the Manager is a wholly owned subsidiary of Capital Power. Certain of the officers of Capital Power are directors and officers of the General Partner.

        The Terms of Reference for the Board denotes that the Board shall be composed of not more than eight members, at least four of whom shall be independent directors who are not officers, directors or employees of Capital Power or its affiliates and are free from any direct or indirect interest, any business or other relationship that could interfere with a director's independence or ability to act in the best interests of the General Partner and Partnership. There are three senior officers and one former senior officer of Capital Power who are members of the Board and are not considered to be independent. The Chairman, who is an executive officer of Capital Power, has a casting vote in case of a tie vote at any meeting of the Board. In order to address these conflicts of interest, the Partnership Agreement provides that all material transactions or agreements between the Partnership and Capital Power, its affiliates or associates must be approved by a majority of the independent directors of the General Partner. Furthermore, members of the Board who are officers of Capital Power are required to declare their interest in, and abstain from voting on, these transactions as provided for in the Management and Operations Agreement and general principles of corporate law. See "Business Risk—Conflict of Interest Risk Related to the Partnership's Relationship with Capital Power Corporation" in the MD&A.


LEGAL PROCEEDINGS

North Carolina PPA arbitration

        The Partnership filed for arbitration with the NCUC and is seeking long term PPAs for its North Carolina facilities. The NCUC issued an Order on Arbitration on January 26, 2011, which provided direction on four fundamental issues. See "Business of the Partnership—Power Purchase Agreements—United States—North Carolina Facilities" and "Business Risks—PPA contract expiry risk" in the Partnership's MD&A.


Colorado

        The Colorado Public Utilities Commission issued its written decision in mid December, 2010, regarding Public Service of Colorado's (PSCo) Emissions Reduction Plan. The decision preserves the Partnership's option to bid Greeley into PSCo's next resource plan proceeding that will consider how best to replace the 463 MW combined capacity of PSCo's Arapahoe 4 and Cherokee 4 coal units. However Management expects a number of parties, including PSCo, to file Requests for Rehearing and Reconsideration Applications so it is premature to forecast the financial impacts of the decision on the Partnership. See "Regulation—U.S. Energy Industry Regulatory Matters—Colorado".


Petrobank

        The Partnership is in dispute with Petrobank Energy and Resources Ltd. (Petrobank) over the propriety of the price escalation mechanism that has been applied since 2006 to natural gas sales under the long-term supply contract pursuant to which it supplies natural gas to the Partnership's Nipigon plant. Petrobank suggests that the Partnership pay Petrobank $2.5 million retroactively and pay for

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natural gas supplied under the contract in the future at a higher rate until expiry of the contract. Petrobank has not specified the increased amount they seek for the balance of the contract, so it is not possible to quantify the potential cost of a loss of this dispute to the Partnership, however Management believes that Petrobank is unlikely to succeed in this dispute because the proper escalator has been applied and because its claim is barred by the Limitations Act of Alberta.


INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Management

        Certain of Capital Power's indirect wholly-owned subsidiaries and the Manager, are parties to the Management and Operations Agreements with the Partnership. See "Management of the Partnership". Under these agreements, Capital Power is compensated by way of certain management and operating fees, including: (i) an operations and maintenance fee, (ii) a base fee, (iii) an incentive fee, and (iv) a commercial enhancement fee.

        As part of the transfer by EPCOR of its power generation business to Capital Power and its related entities in connection with Capital Power's initial public offering, Capital Power acquired the companies that are parties to the Management and Operations Agreements with the Partnership. Prior to that acquisition, the management and operating fees were paid to EPCOR.

        Pursuant to the Management and Operations Agreements, the operations and maintenance fee payable by the Partnership includes both cost pass-through and fixed amounts that escalate each year on the basis of various indices such as the Canadian consumer price index, as set forth in the Management and Operations Agreement. The base fee is equal to 1% of the Partnership's annual cash distributions.

        Pursuant to the Memorandum of Agreement dated June 7, 2009 among the Partnership, EPCOR and Capital Power, the basis for calculating the incentive fee was revised effective June 30, 2009. The incentive fee is equal to 10% of annual distributable cash flow (as defined) in excess of $2.40 per Unit in respect of each fiscal year. Annual distributable cash flow is defined as cash flow from operating activities before changes in non-cash operating working capital plus dividends from PERH less scheduled debt repayments and maintenance capital (but not growth capital). Prior to June 30, 2009, the incentive fee was equal to 20% of annual cash distributions in excess of $2.31 per Unit and less than $2.52 per Unit; and 30% of annual cash distributions in excess of $2.51 per Unit.

        The commercial enhancement fee payable is calculated as 35% of the amount by which net income of the Partnership increases as a result of effecting certain commercial enhancement transactions through energy marketing and trading operations (enhancement fees) in respect of the power facilities. A commercial enhancement transaction generally is any unique opportunity that is not contemplated as part of the normal management of the Partnership's power facilities that may arise for the Manager to effect transactions in respect of any power facility.

        Services provided under the Management and Operations Agreements are subject to the control and direction of the Board. Pursuant to the Partnership Agreement and the Terms of Reference of the IDC established by the Board, the IDC must approve all material transactions or agreements between the Partnership and Capital Power or its associates or affiliates, including all material amendments to, or the renewal of any non-arm's length agreements between the Partnership and Manager.

        The Manager provides services to the Partnership pursuant the Management and Operations Agreements. See "Material Contracts". The primary Canadian agreement is the Second Amended and Restated Management and Operations Agreement dated July 23, 2004 as amended, which has a term expiring June 30, 2017, subject to early termination in certain circumstances, including: (i) by the Manager, on not less than 12 months' notice to the Partnership; (ii) by the Partnership, (A) on the occurrence of a substantial deterioration in the business of the Partnership where within six months

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thereafter the termination is authorized by a resolution approved by not less than 50% of all outstanding Units and not less than 662/3% of all outstanding Units represented at the meeting, (B) where at least 51% of the equity shares of the Manager are not beneficially owned, directly or indirectly, by Capital Power, or (C) if the General Partner is no longer the general partner of the Partnership; and (iii) by either the Manager or the Partnership, in the event of a default in the performance of a material obligation under the agreement by the other, after notice and an opportunity to remedy the default. The Management and Operations Agreements do not expressly provide for an amount to be paid for cancelling the agreements in other circumstances.

        In addition, the Manager is a party to a Transaction Fees and Costs Agreement with the Partnership which provides fees to the Manager upon the completion of any acquisition or disposition of assets by the Partnership based on the aggregate consideration paid in respect of such transactions.

        Fees paid to Capital Power (and prior to June 30, 2009 to EPCOR) by the Partnership under these agreements are set out below:

Years ended December 31 (millions of dollars)
  2010   2009  

Transactions with CPC(1)

             

Revenue—Frederickson duct firing capacity fees

    0.1     0.1  

Cost of fuel—Greeley natural gas contract

    1.5     2.6  

Operating and maintenance expense

    47.5     50.5  

Management and administration

             
 

Base fee

    0.9     1.1  
 

Enhancement fee

    0.1     0.2  
 

General and administrative costs

    8.4     8.0  
           

    9.4     9.3  
           

Acquisition and divestiture fees

        0.2  

Distributions

    29.1     32.2  

Transactions of discontinued operations

             
 

Cost of fuel—Castleton demand charge

        1.1  
 

Operating and maintenance expense—Castleton

        1.4  
           

(1)
Prior to July 1, 2009, EPCOR.


VOTING SECURITIES AND PRINCIPAL HOLDERS OF VOTING SECURITIES

        As of December 31, 2010, the Partnership's principal Unitholder, CPI Investments Inc., together with the General Partner held 16,513,504 Units or approximately 29.6% of the 55,824,528 issued and outstanding Units of the Partnership.


TRANSFER AGENT AND REGISTRAR

        The Partnership's transfer agent and registrar is Computershare Trust Company of Canada at its principal offices in Calgary and Toronto.

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MATERIAL CONTRACTS

        Except for contracts entered into in the ordinary course of business, the Partnership has entered into the following material contracts:

Financing Agreements

Management and Operation Agreements

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General


INTEREST OF EXPERTS

        KPMG LLP are the auditors of the Partnership and have provided opinions with respect to the Partnership's consolidated annual financial statements as at December 31, 2009 and December 31, 2010 and for the fiscal years then ended. KPMG LLP has confirmed that they are independent with respect to the Partnership within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.


ADDITIONAL INFORMATION

        The "Business Risks" section of the Partnership's MD&A dated March 2, 2011 and filed on SEDAR at www.sedar.com is incorporated herein by reference.

        Additional information related to the Partnership may be found under its profile on SEDAR at www.sedar.com.

        Additional financial information is provided in the Partnership's Annual Audited Consolidated Financial Statements for the year ended December 31, 2010 and in the Management's Discussion and Analysis for the same period both of which can be accessed on SEDAR at www.sedar.com or the Partnership's website at www.capitalpowerincome.ca or by contacting the Corporate Secretary at (780) 392-5155.

Remainder of page left intentionally blank

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SCHEDULE A—CAPITAL POWER INCOME L.P. AND SIGNIFICANT SUBSIDIARIES(1)(2)(3)

GRAPHIC


(1)
Certain subsidiaries having assets and sales and operating revenues representing individually less than 10% of the consolidated assets and consolidated sales and operating revenues of the Partnership, and in aggregate less than 20% of the consolidated assets and consolidated sales and operating revenues of the Partnership, have been omitted.

(2)
Series 1 Shares and Series 2 Shares of CPEL have been issued to the public.

(3)
Organization chart is as of January 1, 2011

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SCHEDULE B—TERMS OF REFERENCE FOR
THE BOARD OF DIRECTORS OF CAPITAL POWER INCOME L.P.
(the "Partnership")

INTRODUCTION

II.    COMPOSITION AND BOARD ORGANIZATION

III.  DUTIES AND RESPONSIBILITIES

A.    Managing the Affairs of the Board

        The Board operates by delegating certain of its authorities to management and by reserving certain powers to itself. Certain of the legal obligations of the Board are described in detail in Section IV. Subject to these legal obligations and to the Articles and By-laws of the General Partner and the covenants and agreements contained in the Limited Partnership Agreement made as of March 27, 1997, as may be amended and restated from time to time, among the General Partner, the Initial Limited Partner and subsequent Limited Partners, the Board retains the responsibility for managing its own affairs, including:

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B.    Management and Human Resources

        The Board has the responsibility for the appointment and succession of the officers of the General Partner and the Partnership as well as:

C.    Strategy and Plans

        The Board has the responsibility to:

D.    Financial and Corporate Issues

        The Board has the responsibility to:

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E.    Business and Risk Management

        The Board has the responsibility to:

F.     Policies and Procedures

        The Board has responsibility to:

G.    Compliance Reporting and Corporate Communications

        The Board has the responsibility to:

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IV.    GENERAL LEGAL OBLIGATIONS OF THE BOARD OF DIRECTORS

        A.    The Board is responsible for:

V.     CHAIR

        The Chair of the Board plays a critical Ieadership role in promoting the optimum functioning of the General Partner's Board of Directors and in maintaining a positive working relationship between the Board of Directors and Management and the Partnership and the Partnership's limited partners. The Chair's prime responsibility is seeking to ensure the effective operation of the Board of Directors by managing Board and Shareholder meetings, monitoring and overseeing the strategic agenda of the Corporation, and providing leadership and advice respecting the General Partner's business planning processes and the Partnership's corporate governance. In order to fulfill this mandate, the Chair must seek to ensure that the responsibilities of the Board are well understood by both the Board and Management and that the boundaries between the Board and Management are clearly understood and respected.

        The Chair of the Board reports to the Partnership's limited partners, except in cases in which there exists a conflict of interest between Capital Power and the other limited partners, in which case the Chair (like other Capital Power-elect Directors) must declare the conflict and recuse himself from any discussions regarding the subject of the conflict of interest. In situations in which the Chair experiences a conflict of interest or temporarily cannot perform his or her duties for any other reason, the Lead Director acts as chair.

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        The Chair's duties and obligations include:

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SCHEDULE C—GOVERNANCE COMMITTEE TERMS OF REFERENCE

Establishment of Committee and Procedures

1.     Committee

        A Committee of the Directors to be known as the "Governance Committee" (the "Committee") is hereby established. The Committee shall assist the Board of Directors (the "Board") in developing the Partnership's approach to corporate governance issues, including the response to applicable corporate governance guidelines and standards set by regulators or stock exchanges on which the Partnership's units are listed. The Committee shall also be responsible for assessing the effectiveness of the Partnership's system of corporate governance and where necessary, making recommendations for improvement of the Partnership's system of corporate governance to ensure high standards of governance are achieved and maintained.

2.     Composition of Committee

        The Committee shall consist of a minimum of three Directors, a majority of whom are independent. A member is independent if the member has no direct or indirect material relationship with the Partnership or Capital Power Corporation, ("Capital Power") or any of its subsidiaries which could, in view of the Board, reasonably interfere with the exercise of a member's independent judgment.

3.     Appointment of Committee Members

        The members of the Committee shall be appointed by the Board on the recommendation of the Committee and shall remain members until replaced or until they cease to be Directors of the General Partner of the Partnership.

4.     Vacancies

        Where a vacancy occurs at any time in the membership of the Committee, it shall be filled by the Board on the recommendation of the Committee.

5.     Committee Chair

        Because Capital Power provides management services to the Partnership, the Chair of the Committee must be independent of Capital Power.

        The primary responsibility of the chair of the Committee is to seek to ensure the effective operation of the Committee by managing Committee meetings, leading the Committee's strategic oversight of the Partnership's relationship with Capital Power and providing leadership and advice respecting the General Partner's corporate governance generally. The Committee Chair's duties and responsibilities also include:

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6.     Absence of Committee Chair

        If the Chair of the Committee is not present at any meeting of the Committee, one of the other members of the Committee present at the meeting shall be chosen by the Committee to preside at the meeting.

7.     Secretary of Committee

        The Corporate Secretary of the Partnership shall be the Secretary of the Committee.

8.     Meetings

        The Chair, or any two members of the Committee, may call a meeting of the Committee. The Committee shall meet at least twice per year.

9.     Quorum

        Two members of the Committee, present in person or by telephone or other electronic communication device that permit all persons participating in the meeting to speak to each other, shall constitute a quorum.

10.   Notice of Meetings

        Notice of the time and place of every meeting shall be given in writing or facsimile communication to each member of the Committee at least 24 hours prior to the time fixed for such meeting; provided, however, that a member may in any manner waive a notice of a meeting and attendance of a member at a meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.

11.   Attendance of Management at Committee Meetings

        At the invitation of the Chair of the Committee, Management may attend any meeting of the Committee.

12.   Procedure, Records and Reporting

        The Committee shall fix its own procedure at, and keep records of, its meetings and report to the Board when the Committee may deem appropriate.

13.   Review of Mandate

        The Committee shall review its mandate annually or otherwise, as it deems appropriate, and propose recommended changes to the Board.

14.   Experts

        The Committee Chair, on behalf of the Committee, and any member with the consent of the Committee Chair, is authorized when deemed necessary or desirable to retain independent experts, at the Partnership's expense, to advise the Committee or the member independently on any matter related to their service on the Committee.

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Mandate of Committee

15.   Specific Mandates

        The Committee shall:

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SCHEDULE D—AUDIT COMMITTEE TERMS OF REFERENCE

Establishment of Committee and Procedures

1.     Committee

        A committee of the Directors to be known as the "Audit Committee" or "Committee" is hereby established. The Committee shall be directly responsible for overseeing the work of the external auditor engaged for the purpose of reviewing or attesting services, including the resolution of disagreements between Management and the external auditor regarding financial reporting. The Committee shall monitor the integrity of the financial statements of the Partnership, the compliance by the Partnership with legal and regulatory requirements and the independence and performance of the Partnership's internal audit function and the external auditor.

2.     Composition of Committee

        The Committee shall consist of a minimum of three Independent Directors, each of whom shall be financially literate.

3.     Definition of Financial Literacy

        The Committee and the Partnership's Board of Directors have determined that for the purposes of the Committee's mandate the following definition applies:

        "Financially literate" means the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised in the Partnership's financial statements.

4.     Appointment of Committee Members

        The members of the Committee shall be appointed by the Board with due consideration of the recommendation of the Governance Committee and shall remain members until replaced or until they cease to be Directors of the Partnership.

5.     Vacancies

        Where a vacancy occurs at any time in the membership of the Committee, it shall be filled by the Board with due consideration of the recommendation of the Governance Committee.

6.     Committee Chair

        The Chair of the Committee's prime responsibility is seeking to ensure the effective operation of the Audit Committee by managing Audit Committee meetings, leading the Audit Committee's strategic oversight of the Partnership's financial controls and related risks and providing leadership and advice respecting the General Partner's audit function generally. The Committee Chair's duties and obligations also include:

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7.     Absence of Committee Chair

        If the Chair of the Committee is not present at any meeting of the Committee, the Vice Chair shall preside at the meeting.

8.     Secretary of Committee

        The Corporate Secretary of the Partnership shall be the Secretary of the Committee.

9.     Meetings

        The Chair, any two members of the Committee, the internal auditor, or the external auditor may call a meeting of the Committee. The Committee shall meet at least four times per year.

10.   Quorum

        Two members of the Committee, present in person or by telephone or other electronic communication device that permit all persons participating in the meeting to speak to each other, shall constitute a quorum.

11.   Notice of Meetings

        Notice of the time and place of every meeting shall be given in writing or by facsimile or other electronic communication to each member of the Committee at least 24 hours prior to the time fixed for such meeting; provided, however, that a member may in any manner waive a notice of a meeting and attendance of a member at a meeting is deemed a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.

12.   Attendance of Partnership Officers at Meeting

        At the invitation of the Chair of the Committee, Management may attend any meeting of the Committee.

13.   Procedure, Records and Reporting

        The Committee shall fix its own procedure at, and keep records of, its meetings and report to the Board when the Committee may deem appropriate.

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14.   Review of Mandate and Performance Assessment

        The Committee shall review its mandate annually or otherwise, as it deems appropriate, and propose recommended changes to the Governance Committee and the Board. The Committee shall also conduct a periodic self-evaluation of the performance of the Committee of its responsibilities in accordance with these Terms of Reference. The Committee shall report the results of its evaluation to the Governance Committee and such report may be an oral report by the Committee Chairman.

15.   Experts

        The Committee Chair, on behalf of the Committee, is authorized when deemed necessary or desirable to retain independent counsel and other advisors, at the Partnership's expense, to advise the Committee independently on any matter necessary to carry out its duties. Individual members of the Committee may retain independent counsel and other advisors to advise them, on request to and with the authorization of the Chair. The Committee has authority to set and pay the compensation for any counsel or advisors it retains or employs.

16.   Appointment of the Partnership's External Auditor

        The Committee shall recommend to the Board for nomination, the external auditor for the purpose of preparing or issuing an audit report or performing other audit, review or attestation services for the Partnership, such nomination on approval of the Board shall be confirmed by the General Partner's sole shareholder. The Committee shall also recommend to the Board for approval, the compensation to be paid to the external auditor for audit services and, except as may be otherwise provided herein, shall approve the retention of the external auditor for all non-auditor services and the fees for such services. The Committee is responsible for overseeing the work of the external auditor and shall also receive periodic reports from the external auditor regarding the external auditor's independence, discuss such reports with the external auditor, consider whether provision of non-audit services is compatible with maintaining the auditor's independence, and if so determined by the Committee, recommend that the Board take appropriate action to satisfy itself of the independence of the external auditor.

        All non-audit services to be provided by the external auditor for the Partnership or its subsidiaries shall require pre-approval of the Committee. The Committee may delegate the pre-approval function for non-audit services to one or more members of the Committee. Any exercise of the delegated pre-approval function shall be reported to the Committee at the Committee meeting next following the pre-approval.

        The Committee shall evaluate the performance of the external auditor and determine whether there is an appropriate policy in place relative to the rotation of the lead audit partner. The Committee shall recommend to the Board any replacement of the external auditor.

17.   Oversight in Respect of Financial Disclosure

        The Committee shall to the extent it deems necessary or appropriate:

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18.   Oversight in Respect to Certain Policies

        The Committee shall to the extent it deems necessary or appropriate:

19.   Oversight in Respect of Business Risks and Risk Management

        The Committee shall to the extent it deems necessary or appropriate:

20.   Oversight in Respect of Legal and Regulatory Matters

        The Committee shall to the extent it deems necessary or appropriate review with the Partnership's counsel any legal matters that may have a material impact on the financial statements, the Partnership's compliance policies and any material reports or inquiries received from regulators or governmental agencies.

21.   Oversight in Respect of Internal Audit

        The Committee shall to the extent it deems necessary or appropriate:

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22.   Oversight in Respect of the External Auditor

        The Committee shall to the extent it deems necessary or appropriate:

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23.   Other Responsibilities

        The Committee shall to the extent it deems necessary or appropriate:

24.   Oversight of Committee

        While the Committee has the responsibilities and powers set forth in this mandate, it is not the duty of the Committee to plan or conduct audits or to determine that the Partnership's financial statements and disclosure are complete and accurate or are in accordance with the Canadian GAAP. This is the responsibility of the Partnership's Manager, the Chief Financial Officer, the Controller and the external auditor. The Committee, its Chair and its members are members of the Board, are appointed to the Committee to provide broad oversight of the financial disclosure, financial risk and control related activities of the Partnership, and are specifically not accountable or responsible for the day-to-day operation of such activities. In particular, the member or members who may be identified from time to time as having accounting or related financial experience or education shall not be accountable for giving professional opinions on the internal or external audit of the Partnerships' financial information or financial disclosures. It is expected, however, that Committee members will bring to bear their education and experience in the discharge of the Committee's responsibilities.

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SCHEDULE E—INDEPENDENT DIRECTORS TERMS OF REFERENCE

Establishment of Committee and Procedures

1.     Committee

        A Committee of the Directors to be known as the "Independent Directors Committee" is hereby established. The Committee shall carry out the obligations assigned to them by the Limited Partnership Agreement as amended and restated from time to time.

2.     Composition of Committee

        The Committee shall consist of all independent directors on the Board. "Independent directors" are those Directors who have no direct or indirect material relationship with the Partnership or Capital Power Corporation, ("Capital Power") or any of its subsidiaries which could, in view of the Board, reasonably interfere with the exercise of their independent judgment.

3.     Appointment of Committee Members

        The Board shall appoint all independent directors to serve as members of the Committee and such members shall remain members until replaced or until they cease to be Directors of the General Partner of the Partnership.

4.     Lead Director & Committee Chair

        The Lead Director chairs the Independent Directors Committee and otherwise seeks to ensure that the responsibilities of the Independent Directors are well understood by the Independent Directors, the Board and Management and that the boundaries between the General Partner and the Manager are clearly understood and respected. The primary responsibilities of the Lead Director are therefore to (i) seek to ensure appropriate structures and procedures are in place so the Board can function independently of management; and (ii) lead the process by which the Independent Directors Committee seeks to ensure that the General Partner's Board represents and protects the interests of all limited partners.

        The Lead Director's duties and obligations also include:

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        The Lead Director is nominated by the independent directors and such nomination considered by the Governance Committee and recommended to the Board of Directors for approval. Once so appointed, the Lead Director serves at the pleasure of, and reports to, the Board.

5.     Absence of Lead Director

        If the Chair of the Committee is not present at any meeting of the Committee, one of the other members of the Committee present at the meeting shall be chosen by the Committee to preside at the meeting.

6.     Secretary of Committee

        At the pleasure of the Committee, the Corporate Secretary of the Partnership shall be the Secretary of the Committee.

7.     Meetings

        The Chair, or any two members of the Committee, may call a meeting of the Committee. The Committee shall meet after Board meetings in-camera and as required.

8.     Quorum

        Two members of the Committee, present in person or by telephone or other electronic communication device that permit all persons participating in the meeting to speak to each other, shall constitute a quorum.

9.     Notice of Meetings

        Notice of the time and place of every meeting shall be given in writing or facsimile communication to each member of the Committee at least 24 hours prior to the time fixed for such meeting; provided, however, that a member may in any manner waive a notice of a meeting and attendance of a member

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at a meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.

10.   Attendance of Partnership Officers at Meeting

        At the invitation of the Chair of the Committee, one or more officers of the Partnership or Capital Power may attend any meeting of the Committee.

11.   Procedure, Records and Reporting

        The Committee shall fix its own procedure at meetings, keep records of its proceedings and report to the Board when the Committee may deem appropriate.

12.   Review of Mandate and Performance Assessment

        The Committee shall review its mandate annually or otherwise, as it deems appropriate, and propose recommended changes to the Governance Committee for review and reference to the Board. The Committee shall also conduct a periodic self-evaluation of the performance of the Committee of its responsibilities in accordance with the Committee mandate. The Committee shall report the results of its evaluation to the Governance Committee and such report may be an oral report by the Committee Chairman.

13.   Experts

        The Committee Chair, on behalf of the Committee, and any member with the consent of the Committee Chair, is authorized when deemed necessary or desirable to retain independent professional advisors or experts of whatever background or specialty, at the Partnership's expense, to advise the Committee or the member independently in respect of any matter related to their service on the Committee or as may be necessary or desirable in order to properly discharge the Committee's duties and responsibilities.

14.   Mandate of Committee

        The Committee shall be responsible to review, and if thought appropriate, recommend to the Board for approval:

15.   Balance of Interests

        In connection with their duties as directors generally, Independent Directors will have regard for the position and interests of the public unitholders, with a view to anticipating the instances in which the interests of Capital Power and such unitholders may diverge, so as to ensure in any such instances that the Partnership conducts itself and its business and affairs on the basis of full and timely disclosure of the relevant facts and circumstances to all directors and with due regard to the position and interests of the public unitholders generally.

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16.   Advance Notice of Matters

        The Committee shall be provided with notice, as early as reasonably practicable, of any matter or thing which, if it was to proceed or be pursued, might reasonably be anticipated to require the involvement or approval of the Committee having regard to the role, duties and responsibilities of the Committee. It is recognized that early notification to and involvement of the Committee will enable it to more properly discharge its duties and enhance its ability to minimize any divergence or potential divergence between the interests of Capital Power and the interests of the Partnership's public unitholders. The Partnership President shall be responsible for such early notification and shall, wherever any reasonable doubt exists as to whether any matter may ultimately require the Committee's involvement or approval, the President shall err on the side of notification. In all events, the Committee will be provided with full, complete and timely access to all such information and personnel as it may reasonably request in connection with the discharge of its duties.

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SCHEDULE F—PRESIDENT'S TERMS OF REFERENCE

        The President of the General Partner provides day-to-day leadership and management to the General Partner and represents Management on the Board of Directors. The President's primary duties and objectives include:

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Schedule IV

Audited Consolidated Financial Statements of CPILP
as at and for the Years Ended December 31, 2010, 2009 and 2008


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GRAPHIC            
    KPMG LLP
Chartered Accountants

10125 - 102 Street
Edmonton AB T5J 3V8
Canada
  Telephone
Fax
Internet
  (780) 429-7300
(780) 429-7379
www.kpmg.ca


INDEPENDENT AUDITORS' REPORT

To the Partners of Capital Power Income L.P.

        We have audited the accompanying consolidated balance sheets of Capital Power Income L.P. and subsidiaries ("the Partnership") as of December 31, 2010, 2009, and 2008 and the related consolidated statements of income, partners' equity, comprehensive loss and cash flows for each of the year in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2010, 2009, and 2008 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010 in conformity with Canadian generally accepted accounting principles.

        Accounting principles generally accepted in Canada vary in certain significant respects from U.S. generally accepted accounting principles. Information relating to the nature and effect of such differences is presented in note 27 to the consolidated financial statements.

"signed KPMG"

KPMG LLP
Edmonton, Canada

March 2, 2011, except as to note 27, which is as of July 25, 2011

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Capital Power Income L.P.

CONSOLIDATED STATEMENTS OF INCOME AND LOSS

 
  Years ended December 31  
 
  2010   2009   2008  
 
  (In millions of dollars except units and per unit amounts)
 

Revenues

  $ 532.4   $ 586.5   $ 499.3  

Cost of fuel

    230.7     271.4     288.8  

Operating and maintenance expense

    114.2     103.4     99.1  
               

    187.5     211.7     111.4  

Other costs

                   

Depreciation, amortization and accretion (Note 5)

    98.3     93.3     88.3  

Financial charges and other, net (Note 9)

    40.1     46.4     70.7  

Management and administration

    13.9     15.2     20.2  

Asset impairment charge (Note 8)

            24.1  
               

    152.3     154.9     203.3  
               

Net income (loss) from continuing operations before income tax and preferred share dividends

    35.2     56.8     (91.9 )

Income tax recovery (Note 14)

    9.4     8.9     31.4  
               

Net income (loss) from continuing operations before preferred share dividends

    44.6     65.7     (60.5 )

Preferred share dividends of a subsidiary company (Note 11)

    14.1     7.9     6.6  
               

Net income (loss) from continuing operations

    30.5     57.8     (67.1 )

Loss from discontinued operations (Note 25)

        (0.2 )   (0.7 )
               

Net income (loss)

  $ 30.5   $ 57.6   $ (67.8 )
               

Net income (loss) per unit from continuing operations

  $ 0.55   $ 1.07   $ (1.24 )

Net loss per unit from discontinued operations

            (0.01 )

Net income (loss) per unit

  $ 0.55   $ 1.07   $ (1.26 )
               

Weighted average units outstanding (millions)

    55.0     53.9     53.9  
               

See accompanying notes to the consolidated financial statements.

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Capital Power Income L.P.

CONSOLIDATED STATEMENTS OF CASH FLOW

 
  Years ended December 31  
 
  2010   2009   2008  
 
  (In millions of dollars)
 

Operating activities

                   

Net income (loss) from continuing operations

  $ 30.5   $ 57.8   $ (67.1 )

Items not affecting cash:

                   
 

Depreciation, amortization and accretion

    98.3     93.3     88.3  
 

Asset impairment charge

            24.1  
 

Future income tax recovery

    (13.9 )   (12.4 )   (34.4 )
 

Fair value changes on derivative instruments

    3.6     (6.2 )   98.4  
 

Unrealized foreign exchange losses

        0.3     26.2  
 

Other

    6.6     10.0     8.7  
               

    125.1     142.8     144.2  

Change in non-cash working capital (Note 16)

    (7.3 )   (8.3 )   13.3  
               
 

Cash provided by operating activities of continuing operations

    117.8     134.5     157.5  
 

Cash (used in) provided by operating activities of discontinued operations

        (2.8 )   2.7  
               

Cash provided by operating activities

    117.8     131.7     160.2  
               

Investing activities

                   

Additions to property, plant and equipment and other assets

    (28.3 )   (100.7 )   (40.0 )

Change in non-cash working capital

    (7.2 )   4.2     2.7  

Dividends from equity investment

        1.3     3.2  

Acquisition of Morris Cogeneration LLC (Note 24)

            (90.7 )

Acquisition of equity investment

        (8.8 )    
               
 

Cash used in investing activities of continuing operations

    (35.5 )   (104.0 )   (124.8 )
 

Cash provided by (used in) investing activities of discontinued operations

        11.6     (3.5 )
               

Cash used in investing activities

    (35.5 )   (92.4 )   (128.3 )
               

Financing activities

                   

Distributions paid

    (69.5 )   (127.7 )   (135.8 )

Net borrowings under credit facilities

    8.1     1.8     85.7  

Proceeds from preferred share offering (Note 11)

        100.0      

Long-term debt repaid

    (1.4 )   (1.3 )   (1.1 )

Issue costs

    (0.5 )   (4.1 )    
               

Cash used in financing activities

    (63.3 )   (31.3 )   (51.2 )
               

Foreign exchange gains (losses) on cash held in a foreign currency

    (1.0 )   (1.5 )   2.2  

Increase (decrease) in cash and cash equivalents

    18.0     6.5     (17.1 )

Cash and cash equivalents, beginning of year

    9.5     3.0     20.1  
               

Cash and cash equivalents, end of year

  $ 27.5   $ 9.5   $ 3.0  
               

Supplementary cash flow information

                   

Income taxes paid

  $ 5.6   $ 2.4   $ 6.7  

Interest paid

  $ 38.0   $ 43.6   $ 37.1  
               

See accompanying notes to the consolidated financial statements.

Schedule IV-3


Table of Contents


Capital Power Income L.P.

CONSOLIDATED BALANCE SHEETS

 
  As at December 31  
 
  2010   2009   2008  
 
  (In millions of dollars)
 

ASSETS

                   

Current assets

                   
 

Cash and cash equivalents

  $ 27.5   $ 9.5   $ 3.0  
 

Accounts receivable

    52.5     51.8     60.6  
 

Inventories (Note 4)

    19.5     24.6     23.2  
 

Prepaids and other

    4.0     4.5     5.0  
 

Derivative assets (Note 15)

    10.4     7.8     22.8  
 

Future income taxes (Note 14)

    7.1     1.9     2.3  
 

Current assets of discontinued operations

            2.3  
               

    121.0     100.1     119.2  

Property, plant and equipment (Note 5)

    994.1     1,064.7     1,106.0  

Power purchase arrangements (Note 6)

    290.0     330.4     408.6  

Goodwill (Note 7)

    45.0     47.6     55.1  

Derivative assets (Note 15)

    29.7     31.8     27.1  

Future income taxes (Note 14)

    41.2     35.0     16.8  

Other assets (Note 8)

    62.8     58.5     64.4  

Long-term assets of discontinued operations (Note 25)

            12.0  
               

  $ 1,583.8   $ 1,668.1   $ 1,809.2  
               

LIABILITIES AND PARTNERS' EQUITY

                   

Current liabilities

                   
 

Accounts payable

  $ 52.9   $ 59.6   $ 70.3  
 

Distributions payable

    8.2     7.9     33.9  
 

Long-term debt due within one year (Note 9)

        1.4     1.3  
 

Derivative liabilities (Note 15)

    21.1     2.9     13.0  
 

Current liabilities of discontinued operations

            1.2  
 

Future income taxes (Note 14)

        3.8      
               

    82.2     75.6     119.7  

Long-term debt (Note 9)

    704.5     719.4     798.5  

Derivative liabilities (Note 15)

    81.9     36.4     38.5  

Other liabilities (Note 10)

    37.1     34.8     33.3  

Long-term liabilities of discontinued operations (Note 25)

            4.2  

Future income taxes (Note 14)

    50.7     62.7     60.7  

Preferred shares issued by a subsidiary company (Note 11)

    219.7     219.7     122.0  
               

Partners' equity

    407.7     519.5     632.3  

Commitments (Note 23)

                   

Subsequent event (Note 28)

                   
               

  $ 1,583.8   $ 1,668.1   $ 1,809.2  
               

Approved by CPI Income Services Ltd., as General Partner of Capital Power Income L.P.

 
   
"signed Brian Vaasjo"   "signed Brian Felesky"

Brian T. Vaasjo

 

Brian A. Felesky
Director and
Chairman of the Board
  Director and
Chairman of the Audit Committee

See accompanying notes to the consolidated financial statements.

Schedule IV-4


Table of Contents


Capital Power Income L.P.

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

 
  Years ended December 31  
 
  2010   2009   2008  
 
  (In millions of dollars)
 

Partnership capital (Note 12)

                   

Balance, beginning of year

  $ 1,200.6   $ 1,197.1   $ 1,197.1  

Partnership units issued pursuant to distribution reinvestment plan

    27.0     3.5      
               

Balance, end of year

  $ 1,227.6   $ 1,200.6   $ 1,197.1  
               

Deficit

                   

Balance, beginning of year:

    (543.7 )   (496.1 )   (296.5 )

Net income (loss)

    30.5     57.6     (67.8 )

Distributions

    (96.9 )   (105.2 )   (135.8 )
               

Balance, end of year

  $ (610.1 ) $ (543.7 ) $ (500.1 )
               

Accumulated other comprehensive loss (Note 13)

                   

Balance, beginning of year

  $ (137.4 ) $ (64.7 ) $ 5.1  

Other comprehensive loss

    (72.4 )   (72.7 )   (69.8 )
               

Balance, end of year

  $ (209.8 ) $ (137.4 ) $ (64.7 )
               

Total of deficit and accumulated other comprehensive loss

  $ (819.9 ) $ (681.1 ) $ (564.8 )
               

Partners' equity

  $ 407.7   $ 519.5   $ 632.3  
               

See accompanying notes to the consolidated financial statements.

Schedule IV-5


Table of Contents


Capital Power Income L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

 
  Years ended December 31  
 
  2010   2009   2008  
 
  (In millions of dollars)
 

Net income (loss)

  $ 30.5   $ 57.6   $ (67.8 )

Other comprehensive income (loss), net of income taxes

                   

Losses on translating net assets of self-sustaining foreign operations(1)

    (27.4 )   (65.9 )   (66.0 )

Amortization of deferred gains on derivative instruments de-designated as cash flow hedges to income(2)

    (0.5 )   (0.4 )   (3.8 )

Unrealized losses on derivative instruments designated as cash flow hedges(3)

    (46.7 )   (6.7 )    

Ineffective portion of cash flow hedges reclassified to net income(2)

    2.2     0.3      
               

    (72.4 )   (72.7 )   (69.8 )
               

Comprehensive loss

  $ (41.9 ) $ (15.1 ) $ (137.6 )
               

(1)
Includes income tax expense of $0.6 million (2009 and 2008—$nil).

(2)
Net of income tax of $nil.

(3)
Net of income tax of $14.6 million (2009—$2.5 million; 2008—$nil).

See accompanying notes to the consolidated financial statements.

Schedule IV-6


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements

Note 1. Description of the Partnership

        Capital Power Income L.P. (the Partnership) is a limited partnership created under the laws of the Province of Ontario pursuant to a Partnership Agreement dated March 27, 1997, as amended and restated November 4, 2009. The Partnership commenced operations on June 18, 1997 and currently has independent power generating facilities in British Columbia, Ontario, California, Colorado, Illinois, New Jersey, New York, North Carolina and Washington State.

        CPI Income Services Ltd., the general partner of the Partnership (the General Partner), has the responsibility for overseeing the management of the Partnership and distributions to unitholders. The General Partner is a wholly owned subsidiary of CPI Investments Inc. (Investments). Capital Power Corporation (collectively with its subsidiaries, CPC, unless otherwise indicated) indirectly owns all of the 49 voting, participating shares of Investments and EPCOR Utilities Inc. (EPCOR) indirectly owns all of the 51 voting, non-participating shares of Investments. The General Partner has engaged certain other subsidiaries of CPC (collectively herein, the Manager) to perform management and administrative services on behalf of the Partnership and to operate and maintain the power plants pursuant to management and operations agreements.

Note 2. Significant accounting policies

Basis of presentation

        The consolidated financial statements of the Partnership have been prepared by the management of the General Partner in accordance with Canadian generally accepted accounting principles (GAAP) and include the accounts of the Partnership and of its subsidiaries. All significant intercompany transactions and balances have been eliminated.


Measurement uncertainty

        The preparation of the Partnership's financial statements in accordance with GAAP requires management to make estimates that affect the reported amounts of revenues, expenses, assets and liabilities as well as the disclosure of contingent assets and liabilities at the financial statement date. The Partnership uses the most current information available and exercises careful judgment in making these estimates and assumptions.

        For determining asset impairments, recording financial assets and liabilities and for certain disclosures, the Partnership is required to estimate the fair value of certain assets or obligations. Estimates of fair value may be based on readily determinable market values, depreciated replacement cost or discounted cash flow techniques employing estimated future cash flows based on a number of assumptions and using an appropriate discount rate.

        Adjustments to previous estimates, which may be material, will be recorded in the period they become known.


Revenue recognition

        Power purchase arrangements, steam purchase arrangements and energy services agreements (collectively referred to as power purchase arrangements or PPAs) are long-term contracts to sell power and steam from the Partnership on a predetermined basis. As explained in "Power purchase arrangements containing a lease," PPAs may be classified as a lease (either operating or capital) and the income is recognized in revenue according to lease revenue recognition standards. For those PPAs

Schedule IV-7


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 2. Significant accounting policies (Continued)


that are not considered to contain a lease, income earned on the PPA is recognized in revenue as follows: Revenue from the sales of electricity, steam and natural gas are recognized on delivery or availability for delivery under take or pay contracts. Revenue from certain long-term contracts with fixed payments is recognized at the lower of (1) the megawatt hours (MWhs) made available during the period multiplied by the billable contract price per MWh and (2) an amount determined by the MWhs made available during the period multiplied by the average price per MWh over the term of the contract from the date of acquisition. Any excess of the current period contract price over the average price is recorded as deferred revenue.

        Gains and losses on non-financial derivative instruments settlements are recorded in revenues or cost of fuel, as appropriate.


Financial instruments

        Financial assets are identified and classified as either available for sale, held for trading, held to maturity or loans and receivables. Financial liabilities are classified as either held for trading or other liabilities. Initially, all financial assets and financial liabilities are recorded on the balance sheet at fair value with subsequent measurement determined by the classification of each financial asset and liability.

        Financial assets and financial liabilities held for trading are measured at fair value with the changes in fair value reported in net income. Financial assets held to maturity, loans and receivables and financial liabilities other than those held for trading are measured at amortized cost. Available for sale financial assets are measured at fair value with changes in fair value reported in other comprehensive income until the financial asset is disposed of or becomes impaired. Investments in equity instruments classified as available for sale that do not have quoted market prices in an active market are measured at cost.

        Upon initial recognition, the Partnership may designate financial instruments as held for trading when such financial instruments have a reliably determinable fair value and where doing so eliminates or significantly reduces a measurement or recognition inconsistency that would otherwise arise from measuring assets and liabilities or recognising gains and losses on them on a different basis. The Partnership has designated its cash and cash equivalents as held for trading. All other non-derivative financial assets not meeting the Partnership's criteria for designation as held for trading are classified as available for sale, loans and receivables or held to maturity.

        Financial assets purchased or sold, where the contract requires the asset to be delivered within an established timeframe, are recognized on a settlement date basis.

        Transaction costs on financial assets and liabilities classified as other than held for trading are capitalized and amortized over the expected life of the instrument, based on contractual cash flows, using the effective interest method (EIM). The EIM calculates the amortized cost of a financial asset or liability and allocates the interest income or expense over the term of the financial asset or liability using an effective interest rate.


Derivative instruments and hedging activities

        To reduce its exposure to movements in energy commodity prices, interest rate changes and foreign currency exchange rates, the Partnership uses various risk management techniques including the use of derivative instruments. Derivative instruments may include forward contracts, fixed-for-floating

Schedule IV-8


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 2. Significant accounting policies (Continued)


swaps and option contracts. Such instruments are used to establish a fixed price for an energy commodity, a cash flow denominated in a foreign currency or an interest-bearing obligation. All derivative instruments, including embedded derivatives, are recorded at fair value on the balance sheet as derivative instruments assets or derivative instruments liabilities except for embedded derivatives instruments that are clearly and closely linked to their host contract and the combined instrument is not measured at fair value. Any contract to buy or sell a commodity that was entered into and continues to be held for the purpose of the receipt or delivery of that commodity in accordance with the Partnership's expected purchase, sale or usage requirements is not treated as a derivative. All changes in the fair value of derivatives are recorded in net income unless cash flow hedge accounting is used, in which case changes in fair value of the effective portion of the derivatives are recorded in other comprehensive income.

        The Partnership uses non-financial forward delivery contracts and financial contracts-for-differences to manage the Partnership's exposure to fluctuations in natural gas prices related to obligations arising from its natural gas fired generation facilities. Under the non-financial forward delivery contracts, the Partnership agrees to purchase natural gas at a fixed price for delivery of a pre-determined quantity under a specified timeframe. Under the financial contracts-for-differences derivatives, the Partnership agrees to exchange, with creditworthy or adequately secured counterparties, the difference between the variable or indexed price and the fixed price on a notional quantity of the underlying commodity for a specified timeframe.

        Foreign exchange forward contracts are used by the Partnership to manage foreign exchange exposures, consisting mainly of US dollar exposures, resulting from anticipated transactions denominated in foreign currencies.

        The Partnership may use forward interest rate or swap agreements and option agreements to manage the impact of fluctuating interest rates on existing debt.

        The Partnership may use hedge accounting when there is a high degree of correlation between the risk in the item designated as being hedged (the hedged item) and the derivative instrument designated as a hedge (the hedging instrument). The Partnership documents all relationships between hedging instruments and hedged items at the hedge's inception, including its risk management objectives and its assessment of the effectiveness of the hedging relationship on a retrospective and prospective basis. The Partnership uses cash flow hedges for certain of its anticipated transactions to reduce exposure to fluctuations in changes in natural gas prices. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in other comprehensive income, while the ineffective portion is recognized in net income. The amounts recognized in accumulated other comprehensive income are reclassified into net income in the same period or periods in which the hedged item occurs and is recorded in net income or when the hedged item becomes probable of not occurring. The hedging relationship for the natural gas contracts, which are derivative instruments, was established after the inception of the contracts. The fair value of these contracts at the date of hedge designation is recognized in net income as the natural gas is delivered under the contracts based on the anticipated fair value of the deliveries at the inception of the hedging relationship.

        A hedging relationship is discontinued if the hedging relationship ceases to be effective, if the hedged item is an anticipated transaction and it is probable that the transaction will not occur by the end of the originally specified time period, if the Partnership terminates its designation of the hedging relationship or if either the hedged or hedging instrument ceases to exist as a result of its maturity,

Schedule IV-9


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 2. Significant accounting policies (Continued)


expiry, sale, termination or cancellation and is not replaced as part of the Partnership's hedging strategy.

        If a cash flow hedging relationship is discontinued or ceases to be effective, any cumulative gains or losses arising prior to such time are deferred in accumulated other comprehensive income and recognized in net income in the same period as the hedged item, and subsequent changes in the fair value of the derivative instrument are reflected in net income. If the hedged or hedging item matures, expires, or is sold, extinguished or terminated and the hedging item is not replaced, any gains or losses associated with the hedging item that were previously recognized in other comprehensive income are recognized in net income in the same period as the corresponding gains or losses on the hedged item. When it is no longer probable that an anticipated transaction will occur within the originally determined period and the associated cash flow hedge has been discontinued, any gains or losses associated with the hedging item that were previously recognized in other comprehensive income are recognized in net income in the period.

        When the conditions for hedge accounting cannot be applied, the changes in fair value of the derivative instruments are recognized as described above. The fair value of derivative financial instruments reflects changes in the commodity market prices and foreign exchange rates. Fair value is determined based on exchange or over-the-counter price quotations by reference to bid or asking price as appropriate, in active markets. In illiquid or inactive markets, the Partnership uses appropriate valuation and price modeling techniques commonly used by market participants to estimate fair value. Fair values determined using valuation models require the use of assumptions concerning the amounts and timing of future cash flows. Fair value amounts reflect management's best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates, discount rates for time value and volatility where available. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.


Income taxes

        Future income tax assets and liabilities are determined based on temporary differences between the tax basis of assets and liabilities and their carrying amounts for accounting purposes. Future income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse.

        The Partnership was not subject to Canadian income taxes and accordingly those taxes which are the responsibility of individual partners have not been reflected in these consolidated financial statements. Certain subsidiaries are taxable and applicable income, withholding and other taxes have been reflected in these consolidated financial statements. However, the Partnership is subject to Canadian income taxes after 2010. As a result, the Partnership recognized future income taxes based on the estimated net taxable timing differences which are expected to reverse after 2010.


Cash and cash equivalents

        Cash and cash equivalents include cash or highly liquid, investment-grade, short-term investments and are recorded at fair value.

Schedule IV-10


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 2. Significant accounting policies (Continued)


Inventories

        Inventories represent small parts and other consumables and fuel, the majority of which is consumed by the Partnership in provision of its goods and services, and are valued at the lower of cost and net realizable value. Cost includes the purchase price, transportation costs and other costs to bring the inventories to their present location and condition. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific identification of their individual costs. Previous write downs of inventories from cost to net realizable value can be fully or partially reversed if supported by economic circumstances.


Property, plant and equipment

        Property, plant and equipment is recorded at cost. Power generation plant and equipment, less estimated residual value, is depreciated on a straight-line basis over estimated service lives of one to fifty years. Other equipment, which includes the costs of office furniture, tools and vehicles, is capitalized and depreciated over estimated service lives of three to fifteen years.

        Property, plant and equipment, including asset retirement costs, is periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the asset's fair value is recognized during the period, with a charge to income.


Power purchase arrangements

        On acquisition of power plants with existing PPAs in place, the acquired PPAs are capitalized as an intangible asset and included within the balance sheet as PPAs. The Partnership records acquired PPAs at their fair value and amortizes them over the remaining terms of the contracts.


Power purchase arrangements containing a lease

        The Partnership has entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain leases which convey to the counterparty the right to the use of the Partnership's property, plant and equipment in return for future payments. Such arrangements are classified as either capital or operating leases. PPAs that transfer substantially all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases.

        Finance income related to leases or arrangements accounted for as direct financing leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The net investment is comprised of net minimum lease payments and unearned finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying value of the leased property. Unearned finance income is deferred and recognized in net income over the lease term.

        Payments received under PPAs classified as direct financing leases are segmented into those for the lease and those for other elements on the basis of their relative fair value.

Schedule IV-11


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 2. Significant accounting policies (Continued)


Long-term investments

        Investments that are not controlled by the Partnership, but over which it has significant influence are accounted for using the equity method and recorded at original cost and adjusted periodically to recognize the Partnership's proportionate share of the investee's net income or losses after the date of investment, additional contributions made and dividends received. Other investments are stated at cost. When there has been a decline in value that is other than temporary, the carrying amount of an investment is reduced to its fair value.


Investment in joint venture

        The investment in a joint venture is accounted for using the proportionate consolidation method. Under this method, the Partnership records its proportionate share of assets, liabilities, revenue and expenses of the joint venture.


Goodwill

        Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the net assets acquired based on their fair values. Goodwill is not amortized, but rather is tested for impairment at least annually or more frequently if events and circumstances indicate that a possible impairment may exist. To test for impairment, the fair value of the reporting unit to which the goodwill relates is compared to the carrying amount, including goodwill, of the reporting unit. If the carrying amount of the reporting unit exceeds its fair value, the fair value of the reporting unit's goodwill is compared with its carrying amount to measure the impairment loss, if any. The Partnership determines the fair value of a reporting unit using discounted cash flow techniques and estimated future cash flows.


Other intangible assets

        Other intangible assets consist primarily of emissions allowances and are amortized over their remaining lives.


Asset retirement obligations

        The Partnership recognizes asset retirement obligations for its power plants. The fair value of the liability is added to the carrying amount of the associated plant asset and depreciated accordingly. The liability is accreted at the end of each period through charges to depreciation, amortization and accretion. The Partnership has recorded these asset retirement obligations, as it is legally required to remove the facilities at the end of their useful lives and restore the plant sites to their original condition.


Foreign currency translation

        The Partnership's functional and presentation currency is the Canadian dollar. The Partnership indirectly owns US subsidiaries which are self-sustaining foreign operations translated to Canadian dollars using the current rate method. Assets and liabilities are translated at the exchange rate in effect at the balance sheet date. Revenues and expenses are translated at average exchange rates prevailing during the period. The resulting translation gains and losses are deferred and included in accumulated

Schedule IV-12


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 2. Significant accounting policies (Continued)


other comprehensive income until there is a reduction in the Partnership's net investment in the foreign operations. Prior to October 1, 2008, the US subsidiaries were considered integrated foreign operations.


Net income per unit

        Net income per unit is calculated by dividing net income by the weighted average number of units outstanding, including those held by CPC.

Note 3. Changes in accounting policies

Future accounting changes

International financial reporting standards

        The CICA has announced that Canadian reporting issuers will need to begin reporting under IFRS, including comparative figures, by the first quarter of 2011. In the fourth quarter of 2010, the Audit Committee reviewed accounting policy decisions for all standards that were in effect at the end of the year ended December 31, 2010.

Note 4. Inventories

 
  2010   2009   2008  

Parts and other consumables

  $ 9.0   $ 14.2   $ 7.7  

Fuel

    10.5     10.4     15.5  
               

  $ 19.5   $ 24.6   $ 23.2  
               

        Inventories expensed in cost of fuel and other plant operating expenses were $47.1 million for the year ended December 31, 2010 (December 31, 2009—$21.2 million; December 31, 2008—$40.5 million).

        No write-down of inventory or reversal of a previous write-down was recognized in the years ended December 31, 2010, 2009 or 2008. As at December 31, 2010, 2009 and 2008, no inventories were pledged as security for liabilities.

Note 5. Property, plant and equipment

 
  2010   2009  
 
  Cost   Accumulated
Depreciation
  Net Book
Value
  Cost   Accumulated
Depreciation
  Net Book
Value
 

Land

  $ 4.9   $   $ 4.9   $ 5.0   $   $ 5.0  

Plant and equipment

    1,439.2     455.3     983.9     1,421.6     399.0     1,022.6  

Other equipment

    10.1     9.3     0.8     11.0     8.7     2.3  

Construction in progress

    4.5         4.5     34.8         34.8  
                           

  $ 1,458.7   $ 464.6   $ 994.1   $ 1,472.4   $ 407.7   $ 1,064.7  
                           

Schedule IV-13


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 5. Property, plant and equipment (Continued)

 
  2008  
 
  Cost   Accumulated
Depreciation
  Net Book
Value
 

Land

  $ 3.3   $   $ 3.3  

Plant and equipment

    1,423.9     346.3     1,077.6  

Other equipment

    8.7     7.7     1.0  

Construction in progress

    24.1         24.1  
               

  $ 1,460.0   $ 354.0   $ 1,106.0  
               

        Depreciation, amortization and accretion expense consists of:

 
  2010   2009   2008  

Depreciation of property, plant and equipment

  $ 69.6   $ 65.0   $ 55.9  

Accretion of asset retirement obligations

    2.9     1.9     1.6  

Amortization of PPAs

    25.4     27.8     31.4  

Other amortization

    0.4     (1.4 )   (0.6 )
               

  $ 98.3   $ 93.3   $ 88.3  
               

Note 6. Power purchase arrangements

 
  2010   2009   2008  
 
  Cost   Accumulated
Amortization
  Net Book
Value
  Cost   Accumulated
Amortization
  Net Book
Value
  Cost   Accumulated
Amortization
  Net Book
Value
 

PPAs

  $ 440.9   $ 150.9   $ 290.0   $ 462.8   $ 132.4   $ 330.4   $ 530.0   $ 121.4   $ 408.6  

        The PPAs are being amortized over the remaining terms of the contracts, which range from four months to seventeen years.

Note 7. Goodwill

        The changes in the carrying value of goodwill are as follows:

 
  2010   2009   2008  

Goodwill, beginning of year

  $ 47.6   $ 55.1   $ 50.9  

Foreign currency translation adjustment

    (2.6 )   (7.5 )   4.2  
               

Goodwill, end of year

  $ 45.0   $ 47.6   $ 55.1  
               

Schedule IV-14


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 8. Other assets

 
  2010   2009   2008  

Net investment in lease

  $ 23.7   $ 26.9   $ 33.2  

Other long-term receivable

    17.6          

Long-term investments

    20.3     21.4     19.2  

Receivable from Equistar

        9.1     9.6  

Other intangible assets:

                   
 

Cost

    1.4     1.2     2.5  
 

Accumulated amortization

    (0.2 )   (0.1 )   (0.1 )
               

  $ 62.8   $ 58.5   $ 64.4  
               


Net investment in lease

        The PPA under which the power generation facility located in Oxnard, California operates is considered to be a direct financing lease for accounting. The PPA expires in 2020. The current portion of the net investment in lease of $1.5 million is included in accounts receivable (2009—$1.6 million; 2008—$1.8 million). Financing income for the year ended December 31, 2010 of $2.5 million is included in revenues (2009—$2.9 million; 2008—$2.8 million).


Other long-term receivable

        Other long-term receivable relates to amounts recoverable over the remaining term of the Oxnard PPA for unbilled services.


Long-term investment and asset impairment charge

        The Partnership's common ownership interest in Primary Energy Recycling Holdings LLC (PERH) was accounted for on the equity basis up to August 24, 2009 and on a cost basis thereafter as a result of a recapitalization of PERH and changes to the management agreement between the Partnership, PERH, Primary Energy Recycling Corporation (PERC) and Primary Energy Operations LLC. The Partnership has converted all of its common and preferred interests in PERH to a 14.3% common equity interest in PERH in connection with a recapitalization of PERH pursuant to which all previously outstanding common and preferred interests in PERH, including those held by the Partnership and PERC, were converted to new common equity interests. No gain or loss was recorded on the conversion.

        In November 2009, the Partnership exercised its pre-emptive right to maintain its pro-rata interest (14.3%) in PERH whereby the Partnership subscribed for new common equity interests at an aggregate subscription price of $8.8 million (US$8.3 million).

        The Partnership recorded a pre-tax impairment charge of $24.1 million during the year ended December 21, 2008 to write down the investment based on its fair value.

Schedule IV-15


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 9. Long-term debt

 
  Effective interest rate   2010   2009   2008  

Senior unsecured notes, due June 2036 at 5.95%

    6.12 %   210.0   $ 210.0   $ 210.0  

Senior unsecured notes (US$190.0 million), due July 2014 at 5.90%

    6.16 %   189.0     199.7     231.4  

Senior unsecured notes (US$150.0 million), due August 2017 at 5.87%

    6.01 %   149.2     157.6     182.7  

Senior unsecured notes (US$75.0 million), due August 2019 at 5.97%

    6.11 %   74.6     78.8     91.4  

Secured term loan at 11.25%

    11.57 %       1.4     2.6  

Revolving credit facilities at floating rates

    2.85 %   86.1     78.3     86.7  
                     

          708.9     725.8     804.8  

Less: Current portion of long-term debt

              1.4     1.3  
 

Deferred debt issue costs

          4.4     5.0     5.0  
                     

        $ 704.5   $ 719.4   $ 798.5  
                     


Senior unsecured notes

        The notes are unsecured obligations of the Partnership and, subject to statutory preferred exemptions, rank equally with all other unsecured and unsubordinated indebtedness of the Partnership. Interest on the senior unsecured notes is payable semi-annually.


Revolving credit facilities

        The Partnership has available to it unsecured two-year credit facilities of $100.0 million, $100.0 million and $125.0 million, for a total of $325.0 million, committed to 2012 and uncommitted amounts of $20.0 million and $20.0 million (US$20.0 million). At December 31, 2010, $86.1 million was drawn against these facilities (December 31, 2009—$78.3 million; December 31, 2008—$86.7 million).

        Under the terms of the extendible facilities, the Partnership may obtain advances by way of prime loans, US base rate loans, US LIBOR loans and bankers' acceptances. Depending on the facility, amounts drawn by way of prime loans bear interest at the prevailing Canadian prime rate or the average one-month bankers' acceptance rate plus a spread based on the Partnership's credit rating. Amounts drawn by way of US LIBOR loans bear interest at the prevailing LIBOR rate plus a spread based on the Partnership's credit rating. Amounts drawn by way of bankers' acceptances bear interest at the prevailing bankers' acceptance rate plus a spread based on the Partnership's credit rating. The Partnership's revolving credit facilities may be used for general partnership purposes including working capital support.


Deferred debt issue costs

        At December 31, 2010 deferred debt issue costs were $7.3 million, net of accumulated amortization of $2.9 million (December 31, 2009—deferred debt issue costs were $6.8 million, net of accumulated amortization of $1.8 million; December 31, 2008—deferred debt issue costs were $6.4 million, net of accumulated amortization of $1.4 million).

Schedule IV-16


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 9. Long-term debt (Continued)


Financial charges and other, net

 
  2010   2009   2008  

Interest on long-term debt

  $ 39.0   $ 42.6   $ 40.3  

Foreign exchange losses

    0.3     1.0     26.2  

Interest on Equistar receivable

    (1.8 )        

Losses from equity investment

        3.1     6.3  

Dividend income

        (1.1 )   (1.9 )

Other

    2.6     0.8     (0.2 )
               

  $ 40.1   $ 46.4   $ 70.7  
               

Note 10. Other liabilities

 
  2010   2009   2008  

Asset retirement obligations

  $ 29.3   $ 28.8   $ 28.6  

Deferred revenue

    6.5     4.5      

Other long-term liabilities

    1.3     1.5     4.7  
               

  $ 37.1   $ 34.8   $ 33.3  
               


Asset retirement obligations

 
  2010   2009   2008  

Asset retirement obligations, beginning of year

  $ 28.8   $ 28.6   $ 21.1  

Adjustment to asset retirement obligations

    (1.5 )        

Assumption of Morris asset retirement obligations

            5.9  

Accretion of asset retirement obligations

    2.9     1.9     1.6  

Foreign currency translation adjustment

    (0.9 )   (1.7 )    
               

Asset retirement obligations, end of year

  $ 29.3   $ 28.8   $ 28.6  
               

        At December 31, 2010, the estimated cost to settle the Partnership's asset retirement obligations was $129.4 million (2009—$146.0 million; 2008—$156.9 million) calculated using inflation rates ranging from 2.0% to 3.0% per annum (2009—2.1% to 3.0%; 2008—3.0%). The estimated cash flows were discounted at rates ranging from 6.4% to 7.5% (2009—6.4% to 7.5%; 2008—6.4%—7.5%). At December 31, 2010, the expected timing of payment for settlement of the obligations ranges from 9 to 80 years.

Note 11. Preferred shares issued by a subsidiary company

        In November 2009, a subsidiary of the Partnership issued 4 million 7.0% Cumulative Rate Reset Preferred Shares, Series 2 (the Series 2 Shares) priced at $25.00 per share. The Series 2 Shares pay fixed cumulative dividends of $1.75 per share per annum, as and when declared, for the initial five-year period ending December 31, 2014. The dividend rate will reset on December 31, 2014 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and

Schedule IV-17


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 11. Preferred shares issued by a subsidiary company (Continued)


4.18%. The Series 2 Shares are redeemable at $25.00 per share by the Partnership on December 31, 2014 and on December 31 every five years thereafter. The holders of the Series 2 Shares will have the right to convert their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the Series 3 Shares) of the Partnership, subject to certain conditions, on December 31, 2014 and every five years thereafter. The holders of Series 3 Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the board of directors of the Partnership, at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate and 4.18%.

        A subsidiary of the Partnership has issued 5 million 4.85% Cumulative Redeemable Preferred Shares, Series 1 priced at $25.00 per share with dividends payable on a quarterly basis at the annual rate of $1.2125 per share. On or after June 30, 2012, the shares are redeemable by the subsidiary company at $26.00 per share, declining by $0.25 each year to $25.00 per share after June 30, 2016. The shares are not retractable by the holders. Under the terms of the preferred share issue, the Partnership will not make any distributions on partnership units if the declaration or payment of dividends on the preferred shares is in arrears.

        Dividends will not be paid on the preferred shares if the senior unsecured notes of the Partnership are in default.

        The Partnership paid dividends of $13.1 million in 2010 (2009—$7.2 million; 2008—$6.1 million) and incurred associated net current and future income taxes of $1.0 million (2009—$0.7 million; 2008—$0.5 million) for an after-tax preferred share dividend of $14.1 million (2009—$7.9 million; 2008—$6.6 million).

Note 12. Partners' capital

 
  2010   2009  
 
  Number of
Units
  Millions of
Dollars
  Number of
Units
  Millions of
Dollars
 

Partnership capital, beginning of year

    54,153,871   $ 1,200.6     53,897,279   $ 1,197.1  

Partnership units issued pursuant to distribution

                         
 

reinvestment plan

    1,670,657     27.0     256,592     3.5  
                   

Partnership capital, end of year

    55,824,528   $ 1,227.6     54,153,871   $ 1,200.6  
                   

 

 
  2008    
 
 
  Number of
Units
  Millions of
Dollars
 

Partnership capital, beginning and end of year

    53,897,279   $ 1,197.1  
           

        The Partnership is authorized to issue an unlimited number of limited partnership units. Each unit represents an equal, undivided limited partnership interest in the Partnership and entitles the holder to participate equally in distributable cash and net income. Units are not subject to future calls or assessments and entitle the holder to limited liability. Each unit is transferable, subject to the requirements referred to in the Partnership Agreement.

        In October 2009, the Partnership implemented a Premium Distribution (Premium Distribution is a trademark of Canaccord Capital Corporation) and Distribution Reinvestment Plan (the Plan) that

Schedule IV-18


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 12. Partners' capital (Continued)


provides eligible unitholders with two alternatives to receiving the monthly cash distributions, including the option to accumulate additional units in the Partnership by reinvesting cash distributions in additional units issued at a 5% discount to the Average Market Price of such units (as defined in the Plan) on the applicable distribution payment date. Alternatively, under the Premium DistributionTM component of the Plan, eligible unitholders may elect to exchange these additional units for a cash payment equal to 102% of the regular cash distribution on the applicable distribution payment date.

        In 2010, the weighted average number of units outstanding was 54,968,742 (2009—53,914,046; 2008—53,897,279).

Note 13. Accumulated other comprehensive income

        The components of accumulated other comprehensive income are as follows:

 
  2010   2009   2008  

Cumulative unrealized losses on translating net assets of self-sustaining foreign operations

  $ (159.3 ) $ (131.9 ) $ (66.0 )

Deferred gains on derivatives de-designated as cash flow hedges

    0.4     0.9     1.3  

Unrealized losses on derivative instruments designated as cash flow

                   
 

hedges

    (50.9 )   (6.4 )    
               

Total accumulated other comprehensive income

  $ (209.8 ) $ (137.4 ) $ (64.7 )
               

Note 14. Income taxes

Components of income tax recovery
  2010   2009   2008  

Current income taxes

  $ 0.4   $ 1.3   $ 1.7  

Future income taxes

    (9.8 )   (10.2 )   (33.1 )
               

  $ (9.4 ) $ (8.9 ) $ (31.4 )
               

Schedule IV-19


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 14. Income taxes (Continued)


Reconciliation of income tax recovery

 
  2010   2009   2008  

Net income (loss) from continuing operations before income

  $ 35.2   $ 56.8   $ (91.9 )
 

taxes and preferred share dividends

                   

Combined federal and provincial tax rate

    29.0 %   31.0 %   31.5 %
               

Expected income tax expense (recovery)

    10.2     17.6     (28.9 )

Amounts related to (non-taxable) non-deductible foreign exchange and other permanent differences

    (9.9 )   (6.7 )   2.7  

Changes in valuation allowance

    (0.1 )   (4.5 )   12.7  

Change due to enactment of rate changes

    0.5     0.7      

Income allocated to Partnership unitholders

    (7.5 )   0.1     (15.8 )

Taxes related to prior periods

    1.3     (9.9 )    

Statutory and other rate differences

    1.4     (9.6 )   6.4  

Other

    (5.3 )   3.4     (8.5 )
               

Actual income tax recovery

  $ (9.4 ) $ (8.9 ) $ (31.4 )
               


Future income tax assets and liabilities

 
  2010   2009   2008  

Loss carryforwards

  $ 87.1   $ 75.4   $ 53.9  

Difference in accounting and tax basis of intangible assets

    2.7     4.5     6.7  

Asset retirement obligations

    5.7     4.1     3.9  

Deferred financing charges

    3.5     2.4     1.8  

Non-deductible accrued amounts

    1.7     1.8     2.1  

Unrealized losses on deriviative instruments

    16.0     0.8     5.1  

Deferred revenue

    2.9     1.7      

Long-term receivable

        0.8     1.0  

Other

            0.9  
               

Future income tax assets

  $ 119.6   $ 91.5   $ 75.4  
               

Difference in accounting and tax basis of plant, equipment and PPAs

 
$

(109.2

)

$

(114.5

)

$

(115.4

)

Unrealized foreign exchange gains

    (4.9 )   (4.3 )   (1.6 )

Long-term receivable

    (7.0 )        

Other

    (0.9 )   (2.3 )    
               

Future income tax liabilities

  $ (122.0 ) $ (121.1 ) $ (117.0 )
               

Net future income tax liabilities

 
$

(2.4

)

$

(29.6

)

$

(41.6

)
               

Schedule IV-20


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 14. Income taxes (Continued)


Presented on the balance sheet as follows:

 
  2010   2009   2008  

Current assets

  $ 7.1   $ 1.9   $ 2.3  

Non-current assets

    41.2     35.0     16.8  

Current liabilities

        (3.8 )    

Non-current liabilities

    (50.7 )   (62.7 )   (60.7 )
               

  $ (2.4 ) $ (29.6 ) $ (41.6 )
               


Income taxes

        The Partnership follows the liability method of accounting for income taxes, whereby income taxes are recognized on differences between the financial statement carrying values and the respective income tax basis of assets and liabilities. Future income tax assets and liabilities are measured using the substantively enacted tax rates and laws that will be effect when the temporary differences are expected to be recovered or settled. To the extent that the realization of a future tax asset is not considered 'more likely than not,' a valuation allowance is provided.


Taxation of flow-through entities

        Pursuant to the Income Tax Act (Canada), beginning on January 1, 2011, the Partnership will be subject to a specified investment flow-through (SIFT) distribution tax of 16.5% (15% beginning in 2012) along with a provincial tax component of 10%. The tax rates are equivalent to the substantially enacted corporate income tax rates, but apply to distributions of certain types of income. As the partnership generates cash flows from both Canada and the United States, only the cash flows generated in Canada would be subject to the SIFT tax. Cash flows generated in the United States are exempt from the SIFT tax as they are subject to United States taxation. The Partnership expects that its distributions will be treated as eligible dividends starting on January 1, 2011.

        The net future income tax liability relating to the SIFT legislation decreased $17.0 million to $45.7 million in 2010 (2009—$62.7 million; 2008—$60.7 million) due a reduction in the net taxable temporary differences which are expected to reverse subsequent to 2010. This estimate of the net future tax liability is based on the current best estimate of the accounting and tax values that exist on December 31, 2010. The Partnership and its Canadian subsidiary limited partnerships have net taxable temporary differences of $185.8 million (2009—$245.7 million, 2008—$309.1 million) of which the tax effects of $184.0 million (2009—$250.5 million, 2008—$230.5 million) are reflected in these consolidated financial statements due to the enactment of the SIFT legislation in 2007.


Taxation of corporate subsidiaries

        Current and future taxes have been reflected in respect of taxable income and temporary differences relating to the corporate subsidiaries of the Partnership. The Canadian corporate subsidiaries of the Partnership are subject to tax on their taxable income at a rate of approximately 29% (2009—31.0%; 2008—31.5%) whereas the US corporate subsidiaries are subject to tax on their taxable income at rates varying from 34% to 41% (2009—34.0% to 41.0%; 2008—34.0%—41.0%). Future income taxes relating to the corporate subsidiaries have been reflected in these consolidated

Schedule IV-21


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 14. Income taxes (Continued)


financial statements except in respect of deductible temporary differences of $4.4 million (2009—$4.4 million; 2008—$54.9 million) for which no tax benefit has been recognized.


Income tax loss carry forwards

        As at December 31, 2010, the Partnership has income tax loss carry forwards of approximately US $151.4 million (2009—US$128.9 million, 2008—US$84.8 million) in the US, which may be used to reduce future US taxable income. Of these losses, US$22.3 million (2009—US$22.3 million; 2008 US$22.3 million) expire between 2022 and 2025 with the remainder expiring thereafter and $18.1 million (2009—US$18.1 million; 2008—US$22.3 million) of the losses are restricted under Section 382 of the Internal Revenue Code. Under Section 382 of the Internal Revenue Code of 1986, as amended, the utilization of the restricted losses is limited to an annual amount of US$4.7 million.

        As at December 31, 2010, the Partnership has both non-capital losses and capital losses that are available for carry forward in Canada. For Canadian income tax purposes, there are non-capital loss carry forwards of approximately $120.7 million (2009—$96.7 million; 2008—$56.3 million), which may be used to reduce future income taxes otherwise payable and which expire in the years 2011 to 2030. There are also capital loss carry forwards of $3.5 million (2009—$3.5 million; 2008—$14.9 million) which can be carried forward indefinitely. The tax benefit on $0.3 million (2009—$0.2 million; 2008—$0.1 million) of the non-capital losses carry forwards and on $3.5 million (2009—$3.5 million; 2008—$14.9 million) of the capital loss carry forwards have been fully offset by the recognition of a valuation allowance.


Out of period adjustment

        During the year ended December 31, 2009, the Partnership recorded an out-of-period adjustment of $9.7 million relating to 2007 and 2008 in order to recognize net future income tax assets associated with the Partnership's interest in PERH. Management determined that the impact of the adjustment was not material, either individually or in aggregate, to any of the prior periods' financial statements and accordingly, that a restatement of previously issued financial statements was not necessary.

Note 15. Financial instruments

Fair values and classification of financial assets and liabilities

        The Partnership classifies its cash and cash equivalents and current and non-current derivative instruments assets and liabilities as held for trading and measures them at fair value. Accounts receivable are classified as loans and receivables and accounts payable and distributions payable are classified as other financial liabilities and are measured at amortized cost. The fair values of accounts receivable, accounts payable and distributions payable are not materially different from their carrying amounts due to their short-term nature. The investment in PERH is classified as available for sale and the net investment in lease is classified as loans and receivables. The net investment in lease and other long-term receivable relates to the Oxnard PPA, which is considered a direct financing lease for accounting purposes.

Schedule IV-22


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 15. Financial instruments (Continued)

        The classification, carrying amounts and fair values of the Partnership's other financial instruments are summarized as follows:

 
  2010  
 
  Carrying amount    
   
 
 
  Loans and
receivables
  Other
financial
liabilities
  Total   Total fair
value
 

Other assets—net investment in lease and other long-term receivable

  $ 41.3   $   $ 41.3   $ 42.4  

Long-term debt (including current portion)

        (704.5 )   (704.5 )   (697.7 )

 

 
  2009  
 
  Carrying amount    
   
 
 
  Loans and
receivables
  Other
financial
liabilities
  Total   Total fair
value
 

Other assets—net investment in lease and other long-term receivable

  $ 26.9   $   $ 26.9   $ 27.1  

Other assets—receivable from Equistar

    9.1         9.1   $ 9.1  

Long-term debt (including current portion)

        (720.8 )   (720.8 )   (667.7 )

 

 
  2008  
 
  Carrying amount    
   
 
 
  Loans and
receivables
  Other
financial
liabilities
  Total   Total fair
value
 

Other assets—net investment in lease

                         
 

and other long-term receivable

  $ 33.2   $   $ 33.2   $ 33.1  

Other assets—receivable from Equistar

    9.6         9.6   $ 9.6  

Long-term debt (including current portion)

        (799.8 )   (799.8 )   (685.9 )

        The fair value of the Partnership's long-term debt is based on determining an appropriate yield for the Partnership's debt as at December 31, 2010, 2009 and 2008. This yield is based on an estimated credit spread for the Partnership over the yields of long-term Government of Canada and US Government bonds that have similar maturities to the Partnership's debt. The estimated credit spread is based on the Partnership's indicative spread as published by independent financial institutions.

        The Partnership has used the carrying amount of its investment in PERH as its fair value as the shares are not quoted in an active market and their fair value therefore cannot be measured reliably.

        The fair value of the Partnership's net investment in the financing lease and related long-term receivables is based on the estimated interest rate implicit in a comparable lease arrangement as at December 31, 2010, 2009 and 2008.


Derivative instruments

        Derivative instruments are held to manage financial risk related to energy procurement and treasury management. All derivative instruments, including embedded derivatives, are classified as held

Schedule IV-23


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 15. Financial instruments (Continued)


for trading and are recorded at fair value on the balance sheet unless exempted from derivative treatment as a normal purchase, sale or usage. All changes in their fair value are recorded in net income.

        The derivative instruments assets and liabilities used for risk management purposes consist of the following:

 
  December 31, 2010  
 
  Natural gas   Foreign exchange    
 
 
  Hedges   Non-hedges   Non-hedges   Total  

Derivative instruments assets:

                         
 

Current

  $   $   $ 10.4   $ 10.4  
 

Non-current

            29.7     29.7  

Derivative instruments liabilities:

                         
 

Current

    (16.2 )   (3.0 )   (1.9 )   (21.1 )
 

Non-current

    (76.9 )       (5.0 )   (81.9 )
                   

  $ (93.1 ) $ (3.0 ) $ 33.2   $ (62.9 )
                   

Net notional amounts:

                         
 

Gigajoules (GJs) (millions)

    37.8     6.5              
 

US foreign exchange (US dollars in millions)

                309        

Contract terms (years)

    6.0     0.8 to 2.0     0.2 to 5.5        

 

 
  December 31, 2009  
 
  Natural gas   Foreign exchange    
 
 
  Hedges   Non-hedges   Non-hedges   Total  

Derivative instruments assets:

                         
 

Current

  $ 1.0   $ 2.5   $ 4.3   $ 7.8  
 

Non-current

        6.0     25.8     31.8  

Derivative instruments liabilities:

                         
 

Current

    (2.1 )       (0.8 )   (2.9 )
 

Non-current

    (32.8 )       (3.6 )   (36.4 )
                   

  $ (33.9 ) $ 8.5   $ 25.7   $ 0.3  
                   

Net notional amounts:

                         
 

Gigajoules (GJs) (millions)

    45.0     11.0              
 

US foreign exchange (US dollars in millions)

                395        

Contract terms (years)

    1.0 to 7.0     0.0 to 3.0     0.2 to 6.0        

Schedule IV-24


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 15. Financial instruments (Continued)

 

 
  December 31, 2008  
 
  Natural gas   Foreign exchange    
 
 
  Hedges   Non-hedges   Non-hedges   Total  

Derivative instruments assets:

                         
 

Current

  $   $ 15.5   $ 7.3   $ 22.8  
 

Non-current

        23.5     3.6     27.1  

Derivative instruments liabilities:

                         
 

Current

        (1.5 )   (11.5 )   (13.0 )
 

Non-current

        (0.6 )   (37.9 )   (38.5 )
                   

  $   $ 36.9   $ (38.5 ) $ (1.6 )
                   

Net notional amounts:

                         
 

Gigajoules (GJs) (millions)

        69.0              
 

US foreign exchange (US dollars in millions)

                456.9        

Contract terms (years)

        0.1 to 8.0     0.2 to 6.0        

        The fair value of derivative instruments are determined, where possible, using exchange or over-the-counter price quotations by reference to quoted bid, ask, or closing market prices, as appropriate in active markets. Where there are limited observable prices due to illiquid or inactive markets, the Partnership uses appropriate valuation and price modeling commonly used by market participants to estimate fair value. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. In general, fair value amounts reflect management's best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates, discount rates for time value, and volatility for all of the Partnership's financial instruments. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

        Unrealized and realized pre-tax gains and (losses) on derivative instruments recognized in net income and other comprehensive income were:

 
  Income statement category   2010   2009   2008  

Foreign exchange non-hedges

  Revenue   $ 12.4   $ 59.8   $ (57.6 )

Natural gas non-hedges

  Cost of fuel     (9.3 )   (52.1 )   (30.4 )

Natural gas hedges—ineffective portion

  Cost of fuel     (2.2 )   (0.3 )    

Natural gas hedges—effective portion

  Other comprehensive loss     (59.1 )   (8.9 )    

        If hedge accounting requirements are not met, unrealized and realized gains and losses on natural gas derivatives are recorded in cost of fuel. If hedge accounting requirements are met, realized gains and losses on natural gas derivatives are recorded in cost of fuel while unrealized gains and losses are recorded in other comprehensive income.

        The Partnership has elected to apply hedge accounting effective July 31, 2009, on certain derivative instruments it uses to manage commodity price risk relating to natural gas prices. For the year ended December 31, 2010, the change in the fair value of the ineffective portion of hedging derivatives required to be recognized in the income statement was $2.2 million. Of the $50.9 million of after tax losses related to derivative instruments designated as cash-flow hedges included in accumulated other

Schedule IV-25


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 15. Financial instruments (Continued)


comprehensive income at December 31, 2010, losses of $8.8 million, net of income taxes of $3.2 million are expected to settle and be reclassified to net income during the year ended December 31, 2011. The Partnership's cash flow hedges extend up to 2016.


Fair value hierarchy

        Fair value represents the Partnership's estimate of the price at which a financial instrument could be exchanged between knowledgeable and willing parties in an orderly arm's length transaction under no compulsion to act. Fair value measurements recognized in the consolidated balance sheets are categorized into levels within a fair value hierarchy based on the nature of the valuation inputs, and precedence is given to those fair value measurements calculated using observable inputs over those using unobservable inputs. The determination of fair value requires judgment and is based on market information where available and appropriate. The following levels were established for each input:

        Level 1:    Fair value is based on quoted prices (unadjusted) in active markets for identical instruments. Financial instruments classified in Level 1 include cash and cash equivalents, including highly liquid short term investments.

        Level 2:    Fair value is based on other than unadjusted quoted prices included in Level 1, which are either directly or indirectly observable at the reporting date. Level 2 includes those financial instruments that are valued using commonly used valuation techniques, such as the discounted cash flow model or black-scholes option pricing models. Valuation models use inputs such as quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active but observable, and other observable inputs that are principally derived from or corroborated by observable market data for substantially the full term of the instrument. Financial instruments classified in Level 2 includes commodity, foreign exchange, and interest rate derivatives whose values are determined based on broker quotes, observable trading activity for similar, but not identical instruments, and prices published on information platforms and exchanges.

        Level 3:    Fair value is based unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the instrument. Level 3 includes financial instruments that are also valued using commonly used valuation techniques described in Level 2, however some inputs used in the models may not be based on observable market data and therefore based on the Partnership's best estimate from the perspective of a market participant. There are no financial instruments classified in Level 3 at the reporting date.

        The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based upon the lowest level input that is significant to the derivation of the fair value. The Partnership's assessment of the significance of a particular input to the fair value measurement requires judgment thereby affecting the placement within the fair value hierarchy levels. The following table presents the Partnership's financial instruments measured at fair value on a

Schedule IV-26


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 15. Financial instruments (Continued)


recurring basis in the consolidated balance sheets, classified using the fair value hierarchy described above:

 
  Level 1   Level 2   Level 3   Total  

Financial assets:

                         
 

Cash

  $ 27.5   $   $   $ 27.5  

Derivative instrument assets:

                         
 

Foreign exchange non-hedges

        40.1         40.1  

Derivative instrument liabilities:

                         
 

Natural gas hedges

        (93.1 )       (93.1 )
 

Natural gas non-hedges

        (3.0 )       (3.0 )
 

Foreign exchange non-hedges

        (6.9 )       (6.9 )

        There were no significant transfers between Level 1 and 2 for the period ended December 31, 2010.

Note 16. Changes in non-cash working capital

 
  2010   2009   2008  

Accounts receivable

  $ 8.4   $ 8.5   $ 10.5  

Inventories

    (14.7 )   (1.2 )   (4.7 )

Accounts payable

    (1.1 )   (16.7 )   8.9  

Other

    0.1     1.1     (1.4 )
               

  $ (7.3 ) $ (8.3 ) $ 13.3  
               

Note 17. Risk management

Risk management overview

        The Partnership is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments which include market, interest, credit and liquidity risks. The Partnership's overall risk management process is designed to identify, manage and mitigate business risk which includes financial risk, among others. Financial risk is managed according to objectives, targets and policies set forth by the Board of Directors. Risk management strategies, policies and limits are designed to ensure the risk exposures are managed within the Partnership's business objectives and risk tolerance. The Partnership's risk management objective is to protect and minimize volatility in cash provided by operating activities and distributions therefrom.


Market risk

        Market risk is the risk of loss that results from changes in market factors such as commodity prices, foreign currency exchange rates, interest rates and equity prices. The level of market risk to which the Partnership is exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of the Partnership's financial assets and liabilities held, non-trading physical assets and contract portfolios. Commodity price risk

Schedule IV-27


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 17. Risk management (Continued)


management and the associated credit risk management are carried out in accordance with Partnership's financial risk management policies, as approved by the Board of Directors.

        To manage the exposure related to changes in market risk, the Partnership uses various risk management techniques including the use of derivative instruments. Derivative instruments may include financial and physical forward contracts. Such instruments may be used to establish a fixed price for an energy commodity, an interest-bearing obligation or an obligation denominated in a foreign currency. Market risk exposures are monitored regularly against approved risk limits and control processes are in place to monitor that only authorized activities are undertaken.

        The sensitivities provided in each of the following risk discussions disclose the effect of reasonably possible changes in relevant prices and rates on net income at the reporting date. The sensitivities are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts. The Partnership's actual exposure to market risks is constantly changing as the Partnership's portfolio of debt, foreign currency and commodity contracts change. Changes in fair value based on market variable fluctuations cannot be extrapolated as the relationship between the change in the market variable and the change in fair value may not be linear. In addition, the effect of a change in a particular market variable on fair values or cash flows is calculated without considering interrelationships between the various market rates or mitigating actions that would be taken by the Partnership.

Commodity price risk

        The Partnership is exposed to commodity price risk as part of its normal business operations, particularly in relation to the prices of electricity, natural gas and coal. The Partnership actively manages commodity price risk by optimizing its asset and contract portfolios in the following manner:

        The following represents the sensitivity of net income to derivative instruments that are accounted for on a fair value basis. As at December 31, 2010, with all other variables unchanged, a $1.00/GJ increase (decrease) of the natural gas price is estimated to increase (decrease) net income by approximately $4 million after tax and other comprehensive income by approximately $24 million after tax. This assumption is based on the volumes or position held at December 31, 2010.

Foreign exchange risk

        The Partnership is exposed to foreign exchange risk on its net investment in self-sustaining foreign operations. The risk is that the Canadian dollar value of the US dollar net investment in self-sustaining foreign operations will vary as a result of the movements in exchange rates.

        The Partnership's foreign exchange management policy is to manage economic and material transactional exposures arising from movements in the Canadian dollar against the US dollar. The

Schedule IV-28


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 17. Risk management (Continued)

Partnership's foreign currency exposure arises from anticipated US dollar denominated cash flows from its US operations and from debt service obligations on US dollar borrowings. The Partnership coordinates and manages foreign currency risk through the General Partner's central Treasury function. Foreign exchange risk is managed by considering naturally occurring opposite movements wherever possible and then managing any material residual foreign currency exchange risks according to the policies approved by the Board of Directors.

        The Partnership primarily uses foreign currency forward contracts to fix the Canadian currency equivalent of its US currency expected cash flows thereby reducing its anticipated US denominated transactional exposure. The Partnership's foreign currency risk management practice is to ensure a majority of the net currency exposure on anticipated transactions within 7 years are economically hedged. At December 31, 2010, US$308.9 million of future anticipated net cash flows from its US plants were economically hedged for 2011 to 2016 at a weighted average rate of $1.13 per US $1.00.

        At December 31, 2010, holding all other variables constant, a $0.10 strengthening (weakening) of the Canadian dollar against the US dollar would increase (decrease) net income by approximately $19 million after tax as a result of changes in the fair value of foreign exchange contracts.

        This sensitivity analysis excludes translation risk associated with the application of the current rate and temporal translation methods, financial instruments that are non-monetary items, and financial instruments denominated in the functional currency in which they are transacted and measured.

Interest rate risk

        The Partnership is exposed to changes in interest rates on its cash and cash equivalents and floating rate short-term and long-term obligations. The Partnership is exposed to interest rate risk from the possibility that changes in the interest rates will affect future cash flows or the fair values of its financial instruments. In some circumstances, floating rate funding may be used for short-term borrowings and other liquidity requirements. At December 31, 2010 the Partnership held $86.1 million in floating rate debt (December 31, 2009—$78.3 million; December 31, 2008 $86.7 million). The Partnership may also use derivative instruments to manage interest rate risk. At December 31, 2010, 2009 and 2008 the Partnership did not hold any interest rate derivative instruments.

        Holding all other variables constant and assuming that the amount and mix of floating rate debt remains unchanged from that held at December 31, 2010, a 100 basis point change to interest rates would have a $0.9 million impact on net income and would have no impact on other comprehensive income.


Credit risk

        The electricity and steam generated at the Partnership's facilities are sold under long-term contracts to 23 customers. Customers accounting for 10% or more of the Partnership's revenue in 2010 were as follows:

 
  2010   2009   2008  

Ontario Electricity Financial Corporation

    26%     23%     26%  

San Diego Gas & Electric Company

    11%     10%     18%  

British Columbia Hydro and Power Authority

    11%     10%     11%  

Schedule IV-29


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 17. Risk management (Continued)

        The Partnership has exposure to credit risk associated with counterparty default under the Partnership's PPAs, fuel supply agreements and foreign currency hedges. In the event of a default by a counterparty, existing PPAs may not be replaceable on similar terms as pricing in many of these agreements is favourable relative to their current markets. Credit risk is associated with the ability of counterparties to satisfy their contractual obligations to the Partnership, including payment and performance. Credit risk is managed by making appropriate credit assessments of counterparties on an ongoing basis, dealing primarily with creditworthy counterparties, diversifying the risk by using several counterparties and where appropriate and contractually allowed, requiring the counterparty to provide appropriate security.

Maximum credit risk exposure

        The Partnership has the following financial assets that are exposed to credit risk:

 
  2010  
 
  Canada   US   Total  

Trade receivables

  $ 21.1   $ 31.4   $ 52.5  

Other assets—net investment in lease and other long-term receivable

        41.3     41.3  

Derivative instruments—current assets

    10.4         10.4  

Derivative instruments—non-current assets

    29.7         29.7  
               

  $ 61.2   $ 72.7   $ 133.9  
               

        The maximum credit exposure of these assets is their carrying amount. No amounts were held as collateral at December 31, 2010.

Accounts receivable

        Accounts receivable consist primarily of amounts due from customers including industrial and commercial customers, government-owned or sponsored entities, regulated public utility distributors and other counterparties. The Partnership historically has not experienced credit losses and accordingly has not provided for an allowance for doubtful accounts. The Partnership evaluates the need for an allowance for potential credit losses by reviewing any overdue accounts and monitoring changes in the credit profiles of counterparties. The Partnership manages its credit risk exposures by dealing with creditworthy counterparties and, where appropriate and contractually allowed, taking back appropriate security from the counterparty. The Partnership determines the creditworthiness of counterparties using its own assessments and credit ratings by Standard and Poor's (S&P) and DBRS Limited (DBRS) if available.

        No material accounts receivable were past due and there was no provision for credit losses associated with these receivables and financial derivative instruments as all balances are considered to be fully recoverable. Accounts receivable are mostly from counterparties with an investment grade rating assigned by S&P.

Schedule IV-30


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 17. Risk management (Continued)


Liquidity risk

        Liquidity risk is the risk that the Partnership will not be able to meet its financial obligations as they come due. The Partnership's liquidity is managed centrally through the General Partner's Treasury function. The Partnership manages liquidity through regular monitoring of cash and currency requirements by preparing short-term and long-term cash flow forecasts and matching the maturity profiles of financial assets and liabilities to identify financing requirements. The financing requirements are addressed through a combination of committed and demand revolving credit facilities and access to capital markets.

        As at December 31, 2010, the Partnership had available bank credit facilities of $238.8 million committed to 2012 as discussed in Note 11—Long-term debt. In addition, the Partnership has a Canadian shelf prospectus under which it may raise up to $600.0 million in partnership units or debt securities. The Canadian shelf prospectus expires in August 2012.

        The Partnership has a long-term debt rating of BBB/stable and BBB(high)/under review (negative), assigned by S&P and DBRS respectively.

        The following are the undiscounted cash flow requirements and contractual maturities of the Partnership's financial liabilities, including interest payments as at December 31, 2010:

 
  Within
1 year
  Between
1 & 2 years
  Between
2 & 3 years
  Between
3 & 4 years
  Between
4 & 5 years
  Beyond
5 years
  Total  

Non-derivative financial liabilities:

                                           
 

Long-term debt(1)

  $   $ 86.1   $   $ 189.0   $   $ 433.8   $ 708.9  
 

Interest payments on long-term debt

    39.5     39.1     36.9     32.2     25.7     291.5     464.9  
 

Accounts payable and accrued liabilities(2)

    36.5                         36.5  
 

Distributions payable

    8.2                         8.2  

Derivative financial liabilities:

                                           
 

Net forward exchange contracts

  $ 1.9   $ 2.2   $ 1.4   $ 0.9   $ 0.9   $   $ 7.3  
                               

Total

  $ 86.1   $ 127.4   $ 38.3   $ 222.1   $ 26.6   $ 725.3   $ 1,225.8  
                               

(1)
Excluding deferred debt issue costs of $4.4 million.

(2)
Excluding interest on long-term debt of $10.5 million and non-cash accruals of $5.9 million.

Note 18. Capital management

        The Partnership's primary objectives when managing capital are to safeguard the Partnership's ability to continue as a going concern, provide stable distributions to unitholders, to maintain an investment grade credit rating and to facilitate the acquisition or development of power projects in Canada and the US consistent with the growth strategy of the Partnership. The Partnership's objective of maintaining an investment grade credit rating is subject to change in order to manage the Partnership's growth strategy with changing economic circumstances. The Partnership manages its capital structure in a manner consistent with the risk characteristics of the underlying assets. This

Schedule IV-31


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 18. Capital management (Continued)


overall objective and policy for managing capital remained unchanged in 2010 from the prior comparative period.

        The Partnership considers its capital structure to consist of long-term debt, preferred shares and partners' equity. The following table represents the total capital of the Partnership:

 
  2010   2009   2008  

Long-term debt (including current portion)

  $ 704.5   $ 720.8   $ 799.8  

Preferred shares

    219.7     219.7     122.0  

Partners' equity

    407.7     519.5     632.3  
               

Total capital

  $ 1,331.9   $ 1,460.0   $ 1,554.1  
               

        The Partnership's credit and stability ratings are presented in the following table:

 
  2010   2009   2008

Credit rating

           
 

S&P

  BBB (stable)   BBB+/negative outlook   BBB+
 

DBRS

  BBB(high)/under review (negative)   BBB(high)/negative trend   BBB(high)

Stability rating

           
 

S&P

  Not Rated   SR-2   SR-2
 

DBRS

  STA-2 (low)   STA-2   STA-2

        The Partnership has the following externally imposed requirements on its capital:

        At December 31, 2010, the Partnership's debt to capitalization ratio was 53% (December 31, 2009—49%; December 31, 2008—51%) and ratings of BBB/stable and BBB(high)/under review (negative) were assigned by S&P and DBRS respectively (December 31, 2009—BBB+/negative outlook and BBB(high)/negative trend; December 31, 2008—BBB+ and BBB(high)).

        In order to manage its capital structure, the Partnership may adjust the amount of distributions paid to unitholders, issue or redeem preferred shares, issue or repay debt or issue or buy back partnership units.

Note 19. Related party transactions

        In operating the Partnership's 20 power plants, the Partnership and CPC (and prior to July 1, 2009, EPCOR) engage in a number of related party transactions which are in the normal course of business. These transactions are based on contracts and many of the fees are escalated by inflation. The

Schedule IV-32


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 19. Related party transactions (Continued)


table below summarizes the amounts included in the calculation of net income for the years ended December 31, 2010, 2009 & 2008.

 
  2010   2009   2008  

Transactions with CPC(1)

                   

Revenue—Frederickson duct firing capacity fees

  $ 0.1   $ 0.1   $ 0.1  

Cost of fuel—Greeley natural gas swap contract

   
1.5
   
2.6
   
0.3
 

Operating and maintenance expense

   
47.5
   
50.5
   
45.1
 

Management and administration

                   
 

Base fee

    0.9     1.1     1.4  
 

Incentive fee

            2.3  
 

Enhancement fee

    0.1     0.2     2.4  
 

General and administrative costs

    8.4     8.0     5.9  
               

    9.4     9.3     12.0  
               

Transactions of discontinued operations

                   
 

Cost of fuel—gas demand charge

        1.1     2.2  
 

Operating and maintenance expense

        1.4     2.9  
               

Acquisition and divestiture fees

   
   
0.2
   
1.9
 
               

Distributions

   
29.1
   
32.2
   
41.6
 
               

(1)
Prior to July 1, 2009, EPCOR.


Greeley natural gas swap contract

        The Partnership has entered into a three year natural gas swap contract with CPC to cover most of the anticipated natural gas supply for Greeley.


Operating and maintenance

        CPC is entitled to receive a fee for services related to the operation and maintenance of the power plants under the Management and Operations Agreements. The annual fees are payable on an equal monthly basis. The annual fees for the Canadian plants and two US plants are annually adjusted for inflation. The annual fees for the other US plants are determined using a cost recovery basis.


Base and incentive fee

        CPC is entitled to a base fee and an incentive fee under the Management and Operations Agreements in each fiscal year of the Partnership. The base fee is equal to 1% of the Partnership's annual cash distributions. The incentive fee is equal to 10% of annual distributable cash flow greater than $2.40 per unit. Annual distributable cash flow is defined as cash flow from operating activities before changes in non-cash operating working capital plus dividends from PERH less scheduled debt repayments and maintenance capital.

Schedule IV-33


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 19. Related party transactions (Continued)


Enhancement fee

        CPC can curtail operations of the Ontario power plants and re-sell contracted natural gas at market prices, rather than produce off-peak power at lower rates. CPC is entitled to receive an enhancement fee equivalent to 35% of the incremental profit.


General and administrative costs

        CPC is entitled to a fee related to the salaries and wages for management and administration employees for the US plants. The fee is payable monthly on a cost recovery basis. CPC is also entitled to receive a fee for Canadian support staff costs for public entity services required per the Management and Operations Agreements. The annual fee is payable on an equal monthly basis and is adjusted annually for changes in salary costs.


Acquisition and divestiture fees

        CPC is entitled to acquisition and divestiture fees under the Transaction Fees and Costs Agreements. The fee is based on the transaction value of the acquisition or disposition.


Distributions

        During the year ended December 31, 2010, the Partnership made cash distributions to CPC in the amount proportionate to its ownership interest. At December 31, 2010, CPC owned 29.6% of the Partnership's units (30.5% at December 31, 2009; at December 31, 2008 EPCOR owned 30.6% of the Partnership's units).

Note 20. Joint venture

        A financial summary of the Partnership's investments in the Frederickson joint venture is as follows:

 
  2010   2009   2008  

Current assets

  $ 1.8   $ 4.9   $ 2.3  

Long-term assets

    109.5     120.3     145.3  

Current liabilities

    0.7     0.4     1.0  

Long term liabilities

    0.5     0.5     0.5  

Revenues

    21.3     23.3     23.0  

Expenses

    12.9     15.5     21.9  

Net income

    8.4     7.8     1.1  

Cash provided by operating activities

    13.2     13.3     8.1  

Cash used in investing activities

             

Cash used in financing activities

    (16.4 )   (10.2 )   (8.4 )

Note 21. Operating leases

        From the point of view of a lessor, the terms of the Manchief, Mamquam, Moresby Lake, Greeley and Kenilworth PPAs (2009 and 2008—Manchief, Mamquam, Moresby Lake, Greeley, Kenilworth, Southport and Roxboro PPAs) are operating leases. At December 31, 2010, the carrying amounts of the

Schedule IV-34


Table of Contents


Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 21. Operating leases (Continued)


property, plant and equipment of these facilities was $247.7 million less accumulated depreciation of $46.7 million (2009—$359.7 million and $47.6 million respectively; 2008—$317.6 million and $39.6 million respectively). The Partnership's revenues for the year ended December 31, 2010 include $74.9 million with respect to the PPAs for these plants (2009—$116.2 million; 2008—$141.8 million).

Note 22. Segment disclosures

        The Partnership operates in one reportable business segment involved in the operation of independent power generation plants within British Columbia, Ontario and in the US in California, Colorado, Illinois, New Jersey, New York, North Carolina and Washington State.


Geographic information

 
  2010   2009   2008  
 
  Canada   US   Total   Canada   US   Total   Canada   US   Total  

Revenue

  $ 217.6   $ 314.8   $ 532.4   $ 263.8   $ 322.7   $ 586.5   $ 159.2   $ 340.1   $ 499.3  
                                       

 

 
  As at December 31, 2010   As at December 31, 2009   As at December 31, 2008  
 
  Canada   US   Total   Canada   US   Total   Canada   US   Total  

Assets

                                                       
 

PP&E

  $ 502.2   $ 491.9   $ 994.1   $ 534.5   $ 530.2   $ 1,064.7   $ 559.3   $ 546.7   $ 1,106.0  
 

PPAs

    33.6     256.4     290.0     36.6     293.8     330.4     39.7     368.9     408.6  
 

Goodwill

        45.0     45.0         47.6     47.6         55.1     55.1  
 

Other assets

        62.8     62.8         58.5     58.5         64.4     64.4  
                                       

  $ 535.8   $ 856.1   $ 1,391.9   $ 571.1   $ 930.1   $ 1,501.2   $ 599.0   $ 1,035.1   $ 1,634.1  
                                       

Note 23. Commitments

        As of December 31, 2010 the Partnership's future purchase obligations were estimated as follows, based on existing contract terms and estimated inflation.

 
  2011   2012   2013   2014   2015   Later
years
  Total
payments
 

Natural gas purchase contracts

  $ 51.9   $ 53.7   $ 43.9   $ 47.2   $ 50.7   $ 53.6   $ 301.0  

Natural gas transportation contracts

    12.9     10.4     10.6     10.2     7.6     15.6     67.3  

Operating and maintenance contracts

    27.5     28.1     28.6     29.2     29.8     46.0     189.2  

        The North Bay, Kapuskasing and Nipigon plants operate under fixed long-term natural gas supply contracts and natural gas transportation contracts with built-in annual escalators. Expiry dates for the contracts vary with an average remaining contract life of six years as at December 31, 2010. The remaining fuel requirements, which account for approximately 2% of the power plants' fuel costs, are purchased at current market prices. Morris operates under a long-term natural gas transportation contract expiring in 2013.

        The operating and maintenance contracts with the Manager are based on fixed fees escalated annually by inflation and have expiry terms of June 30, 2017.

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Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 24. Morris acquisition

        On October 31, 2008, the Partnership acquired 100% of the equity interest in Morris Cogeneration LLC (Morris), a combined heat and power facility in Illinois. The total purchase price was $90.7 million including $88.4 million (US$73.4 million) in cash plus acquisition costs of approximately $2.3 million.

        The financial results of Morris are included in the Partnership's consolidated statements of income and loss from the date of acquisition. The purchase price for the acquisition of Morris was allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows:

Current assets excluding cash and derivative instruments assets

  $ 9.9  

Derivative instruments assets—current

    0.7  

Derivative instruments assets—long term

    2.9  

Property, plant and equipment

    87.2  

Power purchase arrangements

    2.1  

Other assets

    1.5  

Current liabilities

    (6.6 )

Asset retirement obligations

    (5.9 )

Contract liabilities

    (1.1 )
       

Fair value of net assets acquired

  $ 90.7  
       

Consideration

       
 

Cash

  $ 88.4  
 

Acquisition costs

    2.3  
       

  $ 90.7  
       

Note 25. Discontinued operations

        The Partnership completed the sale of its Castleton facility (Castleton) on May 26, 2009. The disposition of Castleton resulted in proceeds of $11.9 million (US$10.7 million) less transaction

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Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 25. Discontinued operations (Continued)


costs of $0.2 million (US$0.2 million) and a pre-tax accounting gain of $2.4 million. Revenues and expenses of Castleton were as follows:

 
  2009   2008  
 
  (millions of dollars)
 

Revenues

  $ 2.1   $ 12.9  

Expenses

             
 

Cost of fuel

    2.1     6.5  
 

Operating and maintenance expense

    2.1     4.4  
 

Depreciation and amortization

        3.7  
 

Foreign exchange gains

        (0.2 )
           

Loss from operations

    (2.1 )   (1.5 )

Gain on sale of Castleton

    2.4      
           

Income (loss) before income tax

    0.3     (1.5 )

Income tax expense (recovery)

    0.5     (0.8 )
           

Loss from discontinued operations

  $ (0.2 ) $ (0.7 )
           

        The carrying amounts of the assets and liabilities of the discontinued operations at December 31, 2009 and December 31, 2008 were as follows:

 
  2009   2008  

Assets of the discontinued operations

             
 

Accounts receivable

  $   $ 0.7  
 

Inventories

        1.0  
 

Prepaids and other

        0.6  
           

Current assets of the discontinued operations

        2.3  
 

Property, plant and equipment

        11.2  
 

Future income taxes

        0.8  
           

Long-term assets of the discontinued operations

        12.0  
           

Total assets of the discontinued operations

  $   $ 14.3  
           

Liabilities of the discontinued operations

             
 

Accounts payable

  $   $ 1.2  
 

Asset retirement obligations

        2.1  
 

Future income taxes

        2.1  
           

Long-term liabilities of the discontinued operations

        4.2  
           

Total liabilities of the discontinued operations

  $   $ 5.4  
           

Note 26. Comparative figures

        Certain comparative figures have been reclassified to conform to the current year's presentation. The Partnership made an immaterial adjustment to the 2009 financial statements to reflect the reclassification of $5.2 million of costs from property, plant and equipment to inventory and to

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Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 26. Comparative figures (Continued)


correspondingly decrease cash flow from operating activities and decrease cash flow used in investing activities. There was no impact to net earnings resulting from this adjustment.

Note 27. Canadian and US accounting policy differences

        The consolidated financial statements of the Partnership have been prepared in accordance with Canadian GAAP which differs in some respects from US GAAP. Differences in accounting principles as they pertain to the consolidated financial statements are immaterial except as described below.

        The application of US GAAP would have the following effect on income and comprehensive loss as reported for the years ended December 31, 2010 and 2009:

 
  2010   2009  

Net income in accordance with Canadian GAAP

  $ 30.5   $ 57.6  
 

Preferred share dividends

    14.1     7.9  
 

Change in effective portion of hedging derivatives(a)

    3.9     (2.1 )
           

Net income in accordance with US GAAP

    48.5     63.4  

Attributable to:

             
 

Equity holders of the Partnership

    34.4     55.5  
 

Preferred share dividends of a subsidiary company

    14.1     7.9  
           

  $ 48.5   $ 63.4  
           

Other comprehensive loss in accordance with Canadian GAAP

  $ (72.4 ) $ (72.7 )
 

Change in effective portion of hedging derivatives(a)

    (3.9 )   2.1  
           

Other comprehensive loss in accordance with US GAAP

  $ (76.3 ) $ (70.6 )
           

Attributable to:

             
 

Equity holders of the Partnership

    (90.4 )   (78.5 )
 

Preferred share dividends of a subsidiary company

    14.1     7.9  
           

  $ (76.3 ) $ (70.6 )
           

Net income per unit in accordance with US GAAP—basic and diluted

  $ 0.63   $ 1.03  
           

(a)
Accounting standards under US GAAP requires the measurement of hedge effectiveness incorporate the credit risk of the Partnership or its counterparty. Canadian GAAP does not have a similar requirement which results in changes in the effective portion of the hedging derivatives.

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Capital Power Income L.P.

Notes to the Consolidated Financial Statements (Continued)

Note 27. Canadian and US accounting policy differences (Continued)

        The application of US GAAP would have the following effect on the consolidated balance sheets as reported at December 31, 2010 and 2009:

 
  2010   2009  
 
  Canadian
GAAP
  U.S.
GAAP
  Canadian
GAAP
  U.S.
GAAP
 

Current assets

  $ 121.0   $ 121.0   $ 100.1   $ 100.1  

Long-term assets(b)

    1,462.8     1,467.2     1,568.0     1,573.0  

Current liabilities

    82.2     82.2     75.6     75.6  

Long term liabilities(b)

    874.2     878.6     853.3     858.3  

Partners' equity and preferred shares(c)

    627.4     627.4     739.2     739.2  

(b)
Under Canadian GAAP, deferred financing fees are presented in the consolidated balance sheet as a reduction of the debt balance, while under US GAAP, deferred financing fees are presented as other assets.

(c)
Under Canadian GAAP, the preferred shares issued by a subsidiary company are classified between liabilities and equity, while under US GAAP, they are classified in equity attributed to non-controlling interests.

        U.S. GAAP requires the Partnership's investment in a joint venture to be accounted for using the equity method. However, under an accommodation of the Securities and Exchange Commission, accounting for joint ventures needs not be reconciled from Canadian to U.S. GAAP. The different accounting treatment affects only display and classification and not earnings or partners' equity.

        Under U.S. GAAP, no sub-total would be provided in the operating section of the consolidated statement of cash flows. As well, under U.S. GAAP, reconciliation in the consolidated statement of cash flows would commence with net income instead of income of continuing operation. However, there are no differences in the total operating, investing and financing cash flows.

Note 28. Subsequent event

        On June 20, 2011, the Partnership and Atlantic Power Corporation (Atlantic Power) jointly announced that they have entered into an arrangement agreement to which Atlantic Power would acquire, directly and indirectly, all of the outstanding limited partnership units of the Partnership for $19.40 per limited partnership unit, payable in cash or shares of Atlantic Power (the "Transaction"). The Transaction is expected to be completed in the fourth quarter of 2011, subject to customary approvals including unitholder and shareholder approvals

        In connection with Atlantic Power's acquisition of the Partnership, the Partnership will sell Roxboro and Southport to an affiliate of CPC. The Transaction values the Southport and Roxboro at approximately $121 million. This Transaction will have the effect of reducing the number of Partnership units outstanding by approximately 6.2 million units.

        Additionally, in connection with the Transaction, the management agreement between CPC and the Partnership will be terminated (or assigned to Atlantic Power). Atlantic Power will assume the management of the Partnership.

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Schedule V

Management's Discussion and Analysis of CPILP
for the Year Ended December 31, 2010


Table of Contents

CAPITAL POWER INCOME L.P.

MD&A

For the Year Ended December 31, 2010

Schedule V-1


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MANAGEMENT'S DISCUSSION AND ANALYSIS

        This management's discussion and analysis (MD&A) is dated March 2, 2011 and should be read in conjunction with the accompanying audited consolidated financial statements of Capital Power Income L.P. (collectively with its subsidiaries the Partnership, unless otherwise specifically stated) for the years ended December 31, 2010 and 2009.

        CPI Income Services Ltd., the general partner of the Partnership (the General Partner), is a wholly-owned subsidiary of CPI Investments Inc. (CPI Investments). EPCOR Utilities Inc. (collectively with its subsidiaries, EPCOR) owns 51 voting, non-participating shares of Investments and Capital Power Corporation (collectively with its subsidiaries, CPC) indirectly owns 49 voting, participating shares of Investments. Pursuant to the shareholder agreement in respect of CPI Investments, Capital Power L.P. and EPCOR agreed that: (i) the board of directors of CPI Investments shall consist of three directors; and (ii) EPCOR is entitled to nominate one person for election to the board of directors of CPI Investments. In accordance with its terms of reference, the Audit Committee of the Board of Directors (the Board) of the General Partner, reviews the contents of the MD&A and recommends its approval by the Board. The Board has approved this MD&A.

        This discussion contains certain forward-looking information and readers are advised to read this discussion in conjunction with the cautionary statement regarding forward-looking information and statements at the end of this MD&A.


OPERATION OF THE PARTNERSHIP

        The General Partner is responsible for management of the Partnership. The Board of the General Partner declares the cash distributions to the Partnership's unitholders. The General Partner has engaged CP Regional Power Services Limited Partnership and Capital Power Operations (USA) Inc. (collectively herein, the Manager), both subsidiaries of CPC, to perform management and administrative services for the Partnership and to operate and maintain the power plants pursuant to management and operations agreements.

        The Partnership's power plants use natural gas, fuel oil, waste heat, wood waste, coal, tire-derived fuel, water flows or a combination of these energy sources to produce electricity and steam.


STRATEGY

        On October 5, 2010, the Partnership and CPC announced that the Partnership would initiate a process to review its strategic alternatives. This decision was the result of separate strategic review processes undertaken by the Special Committee of the independent directors of the Partnership to maximize value for the Partnership's unitholders and by CPC to maximize value for CPC's shareholders. The initiation of the strategic review was not in response to any proposed transaction for the Partnership and there is no assurance that it will lead to a transaction. The process to review strategic alternatives is ongoing and the Partnership anticipates it will be able to provide an update in the second quarter of 2011. During the process to review the strategic alternatives it is anticipated that the Partnership will continue to provide the same amount of monthly distributions to its unitholders, maintain the same investor proposition supported by its high quality portfolio of contracted power assets and deliver on business plan priorities.


SIGNIFICANT EVENTS

Completion of the Oxnard repowering

        The Partnership completed the replacement of the existing GE LM5000 natural gas turbine with a more efficient and reliable GE LM6000 at Oxnard at a cost of US$19.2 million. The repowering project was completed on May 21, 2010, in time for the summer peak demand season in Southern California.

Schedule V-2


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Resolution of Equistar bankruptcy proceedings

        Equistar Chemicals, L.P. (Equistar) has emerged from Chapter 11 proceedings with no impact to the operations of the Morris facility. The Partnership has received payment of US$12.4 million for pre-petition services under the Morris Energy Services Agreement (ESA) and interest as stipulated in the ESA. Accordingly, net income and cash provided by operating activities for the second quarter include the reversal of a $2.1 million allowance for doubtful accounts provision and interest income of $1.8 million.

Arbitration ruling for North Carolina plants and completion of enhancement project

        On January 27, 2011, the North Carolina Utilities Commission (NCUC) issued an Order on Arbitration (Order) relating to Power Purchase Agreements (PPAs) with Progress Energy Inc. (Progress) for the Partnership's North Carolina facilities. The PPAs for the Partnership's two North Carolina facilities expired on December 31, 2009 and the Partnership initiated an arbitration process with the NCUC in October 2009, seeking long-term PPAs including pricing terms reflecting Progress' full avoided costs, including both capacity and energy components. The arbitration ruling supported the majority of the Partnerships positions. The NCUC Order ruled on four fundamental issues in the arbitration:

        While the NCUC ruling supported the majority of the Partnership's positions, it did not completely align with the Partnership's economic projections. Accretion for the enhancement project at the North Carolina facilities will be significantly lower than the $0.10 per unit previously disclosed. The Partnership will specifically quantify and disclose the project's financial expectations once PPA terms have been finalized, which is expected to be in the second quarter.

        In the fourth quarter of 2010, the Partnership completed the final phase of the enhancement project on the North Carolina facilities designed to reduce environmental emissions and improve economic performance by increasing the use of tire-derived fuel and wood waste in the fuel mix. Project costs incurred to December 31, 2010 were US$82 million with an additional US$5 million to be spent in 2011 on access roads and final testing. The Partnership had anticipated a reduction in the capacity of Southport and Roxboro to approximately 88 megawatts (MW) and 46 MW respectively as a result of the increased use of wood waste and tire-derived fuel. The reduction in the capacity levels as a result of the change to a greater level of wood waste and tire-derived fuel in the fuel mix may be

Schedule V-3


Table of Contents


greater than previously expected. Recent testing indicates the plants may only be able to achieve capacities of 84-87 MW at Southport and 42-44 MW at Roxboro based on the targeted fuel mix. Management is assessing whether a shortfall in capacity can be practically resolved.


POWER AND STEAM GENERATION CAPACITY

 
  Energy Source   POWER
(MW)
  STEAM
(MLBS/HR)
 

Ontario plants

                 
 

Nipigon(1)

  Natural gas/waste heat     40      
 

North Bay(1)

  Natural gas/waste heat     40      
 

Kapuskasing(1)

  Natural gas/waste heat     40      
 

Tunis(1)

  Natural gas/waste heat     43      
 

Calstock(1),(2)

  Wood waste/waste heat     35      

Williams Lake(2)

  Wood waste     66      

BC hydroelectric plants(3)

               
 

Mamquam

  Water flows     50        
 

Moresby Lake(4)

  Water flows     6        

Northwest US plants

                 
 

Manchief(5)

  Natural gas     300      
 

Greeley(6)

  Natural gas     72     170  
 

Frederickson(7)

  Natural gas     125      

California plants

                 
 

Naval Station(8)

  Natural gas/fuel oil     47     479  
 

North Island(6)

  Natural gas     40     390  
 

Naval Training Center(8)

  Natural gas/fuel oil     25     220  
 

Oxnard(6)

  Natural gas     49     120  

Curtis Palmer(3)

  Water flows     60      

Northeast US natural gas plants

                 
 

Kenilworth(6)

  Natural gas     30     78  
 

Morris(6),(9)

  Natural gas     177     1,080  

North Carolina plants

                 
 

Southport(10)

  Wood waste/tire-derived fuel/coal     103     1,080  
 

Roxboro(10)

  Wood waste/tire-derived fuel/coal     52     540  

(1)
The Ontario natural gas plants use a process called enhanced combined cycle generation that uses both natural gas and waste heat as energy sources. These plants and the Calstock plant are located adjacent to TransCanada's Canadian Mainline natural gas compressor stations.

(2)
Williams Lake and Calstock use wood waste from local mills as their primary source of energy.

(3)
The Curtis Palmer, Mamquam and Moresby Lake hydroelectric facilities rely on water flows to produce electricity.

(4)
Moresby Lake was previously named Queen Charlotte.

(5)
Manchief is a simple-cycle natural gas facility.

(6)
Greeley, North Island, Oxnard, Kenilworth and Morris are natural gas combined heat and power facilities.

(7)
Frederickson is a combined cycle natural gas plant. Capacity for Frederickson is the Partnership's 50.15% interest.

Schedule V-4


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(8)
Naval Station and Naval Training Center are dual fuel (natural gas and No. 2 distillate fuel oil) fired combined heat and power facilities.

(9)
Morris was acquired on October 31, 2008.

(10)
The Southport and Roxboro combined heat and power facilities are fueled by wood waste, tire-derived fuel and coal. The capacity of each plant is based on using primarily coal. When the targeted proportion of wood waste and tire-derived fuel is used, capacities are expected to be 88 MW at Southport and 46 MW at Roxboro, based on original project expectations and subject to confirmation.

        Of the Partnership's fleet of 20 power plants, 18 have PPAs in place that expire between April 30, 2011 and 2027. The PPAs for the two North Carolina facilities expired on December 31, 2009. The electric output from the North Carolina facilities is sold to Progress. The NCUC has ordered that Progress continue to pay for the output of the North Carolina facilities pursuant to the terms of the PPAs that expired December 31, 2009 until new PPAs are entered (see Significant Events—Arbitration ruling for North Carolina plants and completion of enhancement project). Eight of the Partnership's power plants also have steam purchase agreements (SPAs) with expiry dates ranging from 2012 to 2023. The existence of long-term sales contracts combined with long-term energy supply and operating contracts reduces the financial risk to unitholders, minimizes commodity price risk and increases the stability and security of long-term cash flows.

Schedule V-5


Table of Contents


Consolidated Results-at-a-Glance(1)

Years ended December 31
  2010   2009(4)   2008  
(millions of dollars except unit and per unit amounts)
   
   
   
 

Revenues

                   
 

Ontario plants

    143.2     145.4     161.9  
 

Williams Lake

    42.2     42.9     38.2  
 

BC hydroelectric plants

    19.8     15.7     16.7  
 

Northwest US plants

    57.7     63.1     62.1  
 

California plants

    112.6     97.0     145.3  
 

Curtis Palmer

    36.9     42.1     34.5  
 

Northeast US natural gas plants(2)

    72.8     90.6     45.4  
 

North Carolina plants

    36.2     27.3     59.8  
 

PERC management and incentive fees

    3.2     3.6     3.5  
               

    524.6     527.7     567.4  
 

Fair value changes on foreign exchange contracts

    7.8     58.8     (68.1 )
               

    532.4     586.5     499.3  

Operating margin(1)

                   
 

Ontario plants

    46.0     52.7     69.5  
 

Williams Lake

    24.3     27.8     25.2  
 

BC hydroelectric plants

    14.8     11.1     12.0  
 

Northwest US plants

    34.2     36.7     32.0  
 

California plants

    28.4     29.8     32.2  
 

Curtis Palmer

    31.5     36.3     29.3  
 

Northeast US natural gas plants(2)

    17.4     18.4     6.0  
 

North Carolina plants

    (7.3 )   (10.0 )   1.2  
 

PERC management and incentive fees

    1.8     2.5     2.5  
               

    191.1     205.3     209.9  
 

Fair value changes on foreign exchange and natural gas contracts

    (3.6 )   6.4     (98.5 )
               

    187.5     211.7     111.4  

Net income (loss)

    30.5     57.6     (67.8 )
 

Per unit

  $ 0.55   $ 1.07   $ (1.26 )

Cash provided by operating activities of continuing operations

    117.8     134.5     157.5  
 

Per unit(1)

  $ 2.14   $ 2.50   $ 2.92  

Capital expenditures

    28.3     100.7     40.0  

Long-term debt

    704.5     720.8     799.8  

Distributions

    96.9     105.2     135.8  
 

Per unit

  $ 1.76   $ 1.95   $ 2.52  

Payout ratio(1)(3)

    89 %   86 %   111 %

Total assets

    1,583.8     1,668.1     1,809.2  

Weighted average units outstanding (millions)

    55.0     53.9     53.9  

(1)
The selected three-year annual financial data has been prepared in accordance with Canadian generally accepted accounting principles except for operating margin, cash provided by operating activities of continuing operations per unit and payout ratio. See Non-GAAP

(2)
Northeast US Gas Plants include Morris from the dates of acquisition of October 31, 2008 and have been restated to reflect the operations of Castleton as discontinued operations. Castleton was sold in May 2009.

Schedule V-6


Table of Contents

(3)
Payout ratio is cash distributions divided by cash provided by operating activities of continuing operations excluding operating capital changes less maintenance capital expenditures.

(4)
The Partnership made an immaterial adjustment to the 2009 financial statements to reflect the reclassification of $5.2 million of property, plant and equipment to inventory resulting in a decrease in cash provided by operating activities and capital expenditures. There was no impact to net earnings resulting from this adjustment.

        Revenues excluding fair value changes in foreign exchange contracts were $524.6 million for the year ended December 31, 2010 compared to $527.7 million in 2009. The decrease was primarily due to lower foreign exchange rates, lower prices on settled foreign exchange contracts and lower fuel recovery revenues at Kenilworth caused by lower natural gas supply prices which also results in a decrease in fuel costs. Partially offsetting these decreases was higher revenues at Oxnard in 2010 compared to 2009 as the completion of the turbine upgrade was considered to be sold to Southern California Edison Company (SCE) in exchange for a long-term receivable in 2010. For accounting purposes, the PPA for Oxnard is considered a direct financing lease that transfers the ownership of the plant to the SCE. Accordingly, the turbine upgrade at Oxnard results in a sale and receivable being recorded to reflect the improved economics of the leasing arrangement.

        Operating margin excluding fair value changes in foreign exchange and natural gas supply contracts for the year ended December 31, 2010 decreased by $14.2 million. The decrease in operating margin was primarily the result of low waste heat availability at the Ontario facilities, lower water flows at Curtis Palmer, lower excess energy prices at Williams Lake and lower prices on the foreign exchange contracts that settled in 2010 than those that settled in 2009. These declines were partially offset by higher generation at the BC hydroelectric plants due to higher water flows. Operating margin is defined below under Non-GAAP Measures.

        Unrealized fair value changes in derivative instruments recorded for accounting purposes are not representative of their economic value when considering them in conjunction with the economically hedged item such as future natural gas purchases, future power sales or future US dollar cash flows.


CONSOLIDATED RESULTS OF OPERATIONS

(millions of dollars)
   
 

Cash provided by operating activities of continuing operations for the year ended December 31, 2009

    134.5  

Interest from Equistar and reversal of provision

    3.9  

Higher operating margin at BC hydroelectric plants

    3.7  

Higher operating margin at North Carolina plants

    2.7  

Higher operating margin at Naval plants

    2.1  

Changes in operating working capital

    1.0  

Lower operating margin at Ontario plants

    (6.7 )

Increase in preferred share dividends

    (6.2 )

Lower operating margin at Curtis Palmer

    (4.9 )

Lower operating margin at Oxnard

    (3.5 )

Lower operating margin at Williams Lake

    (3.5 )

Lower operating margin at Manchief

    (3.1 )

Other

    (2.2 )
       

Cash provided by operating activities of continuing operations for the year ended December 31, 2010

    117.8  
       

        The Partnership reported cash provided by operating activities of continuing operations of $117.8 million or $2.14 per unit for the year ended December 31, 2010 compared to $134.5 million or

Schedule V-7


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$2.50 per unit in 2009. Cash provided by operating activities of continuing operations per unit is defined below under Non-GAAP Measures. The $16.7 million decrease in cash provided by operating activities of continuing operations for 2010 compared to 2009 is primarily due to the following:

        Decreases were partially offset by the following:

Schedule V-8


Table of Contents

(millions of dollars)
   
 

Cash provided by operating activities of continuing operations for the year ended December 31, 2008

    157.5  

Impact of full year cash flow from Morris, excluding interest paid

    17.5  

Higher operating margin at Curtis Palmer

    7.0  

Higher operating margin at the Northwest US plants

    4.7  

Lower management and administration costs

    2.6  

Changes in operating working capital

    (21.6 )

Lower operating margin at the Ontario plants

    (16.8 )

Lower operating margin at the North Carolina plants

    (11.2 )

Higher interest expenses

    (4.1 )

Other

    (1.1 )
       

Cash provided by operating activities of continuing operations for the year ended December 31, 2009

    134.5  
       

        The Partnership reported cash provided by operating activities of continuing operations of $134.5 million or $2.50 per unit for the year ended December 31, 2009 compared to $157.5 million or $2.92 per unit in 2008. Cash provided by operating activities of continuing operations per unit is defined below under Non-GAAP Measures. The $17.8 million decrease in cash provided by operating activities of continuing operations for 2010 compared to 2009 is primarily due to the following:

        Decreases were partially offset by the following:

Schedule V-9


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(millions of dollars)
   
 

Net income from continuing operations for the year ended December 31, 2009

    57.8  
       

Interest from Equistar and reversal of provision

    3.9  

Higher operating margin at BC hydroelectric plants

    3.7  

Higher operating margin at North Carolina plants

    2.7  

Higher operating margin at Naval plants

    2.1  

Fair value changes on natural gas supply and foreign exchange contracts

    (10.0 )

Lower operating margin at Ontario plants

    (6.7 )

Increase in preferred share dividends

    (6.2 )

Lower operating margin at Curtis Palmer

    (4.9 )

Increase in depreciation, amorization and accretion

    (4.6 )

Lower operating margin at Oxnard

    (3.5 )

Lower operating margin at Williams Lake

    (3.5 )

Lower operating margin at Manchief

    (3.1 )

Other

    2.8  
       

Net income from continuing operations for the year ended December 31, 2010

    30.5  
       

        Net income from continuing operations was $30.5 million or $0.55 per unit for the year ended December 31, 2010 compared to $57.8 million or $1.07 per unit in 2009. In addition to the items described above for the change in cash provided by operating activities of continuing operations, the decrease in net income of $27.3 million was the result of the following:

Schedule V-10


Table of Contents

(millions of dollars)
   
 

Net loss from continuing operations for the year ended December 31, 2008

    (67.1 )
       

Fair value changes on natural gas supply and foreign exchange contracts

    104.9  

Foreign exchange losses in 2008

    26.2  

Asset impairment charge in 2008

    24.1  

Contribution of Morris acquired October 31, 2008, excluding interest paid

    13.3  

Higher operating margin at Curtis Palmer

    7.0  

Higher operating margin at the Northwest US plants

    4.7  

Lower management and administration costs

    2.6  

Decrease in income tax recovery

    (22.5 )

Lower operating margin at the Ontario plants

    (16.8 )

Lower operating margin at the North Carolina plants

    (11.2 )

Higher depreciation and amortization mainly due to the Morris acquisition in 2008

    (5.0 )

Higher interest expenses

    (4.1 )

Other

    1.7  
       

Net income from continuing operations for the year ended December 31, 2009

    57.8  
       

        Net income from continuing operations was $57.8 million or $1.07 per unit for the year ended December 31, 2009 compared to a net loss from continuing operations of $67.1 million or $1.24 per unit in 2008. In addition to the items described above for the change in cash provided by operating activities of continuing operations, the increase in net income of $124.9 million was the result of the following:

        Increases were partially offset by the following:

Schedule V-11


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NON-GAAP MEASURES

        The Partnership uses operating margin as a performance measure, cash provided by operating activities of continuing operations per unit as a cash flow measure and payout ratio as a distribution sustainability measure. These terms are not defined financial measures according to Canadian generally accepted accounting principles (GAAP) and do not have standardized meanings prescribed by GAAP. Therefore, these measures may not be comparable to similar measures presented by other enterprises.

        The Partnership uses operating margin to measure the financial performance of plants and groups of plants. A reconciliation from operating margin to net income before tax and preferred share dividends is as follows:

Years ended December 31 (millions of dollars)
  2010   2009   2008  

Operating margin

    187.5     211.7     111.4  

Deduct:

                   
 

Depreciation, amortization and accretion

    98.3     93.3     88.3  
 

Financial charges and other, net

    40.1     46.4     70.7  
 

Management and administration

    13.9     15.2     20.2  
 

Asset impairment charge

            24.1  
               

Net income (loss) from continuing operations before tax and preferred share dividends

    35.2     56.8     (91.9 )
               

        Cash provided by operating activities of continuing operations per unit is cash provided by operating activities of continuing operations divided by the weighted average number of units outstanding in the period.

        Payout ratio is defined as distributions divided by cash provided by operating activities of continuing operations excluding working capital changes less maintenance capital expenditures. Working capital changes have been excluded from this measure as short-term changes in working capital are expected to be largely reversed in future periods or represent reversals from prior periods. Non-maintenance capital spending has been excluded from this measure as capital expenditures related to an expansion of the productive capacity of the business represent a long-term investment beyond the maintenance capital requirements of the existing business.

        The composition of the operating margin, cash provided by operating activities of continuing operations per unit and payout ratio used in this MD&A is consistent with December 31, 2009 reporting.

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OPERATING MARGIN(1) AND PLANT OUTPUT

Years ended December 31
  GWh   2010   GWh   2009  
 
   
  (millions of
dollars)

   
  (millions of
dollars)

 

Ontario plants

    1,276     46.0     1,330     52.7  

Williams Lake

    560     24.3     362     27.8  

BC hydroelectric plants

    306     14.8     232     11.1  

Northwest US plants

    741     34.2     990     36.7  

California plants

    935     28.4     971     29.8  

Curtis Palmer

    333     31.5     356     36.3  

Northeast US natural gas plants(2)

    604     17.4     657     18.4  

North Carolina plants

    258     (7.3 )   65     (10.0 )

PERC management

        1.8         2.5  

Fair value changes on derivative contracts

        (3.6 )       6.4  
                   

    5,013     187.5     4,963     211.7  
                   

Weighted average plant availability(3)

                         
 

Ontario plants

          95 %         93 %
 

Williams Lake

          96 %         98 %
 

BC hydroelectric plants

          91 %         86 %
 

Northwest US plants

          94 %         97 %
 

California plants

          91 %         93 %
 

Curtis Palmer

          100 %         94 %
 

Northeast US natural gas plants(2)

          98 %         99 %
 

North Carolina plants

          93 %         69 %
                       

Total weighted average availability

          95 %         92 %
                       

Average price per MWh

                         
 

Ontario plants

        $ 108         $ 104  
 

Williams Lake

        $ 75         $ 119  
 

BC hydroelectric plants

        $ 65         $ 68  
 

California plants

        $ 102         $ 100  
 

Curtis Palmer

        $ 111         $ 118  
 

North Carolina plants

        $ 140         $ 420  

(1)
Operating margin is a non-GAAP financial measure. See Non-GAAP Measures.

(2)
Restated to reflect the operations of Castleton as discontinued operations. Castleton w as sold in May 2009.

(3)
Plant availability represents the percentage of time in the year that the plant is available to generate power, whether actually running or not, and is reduced by planned and unplanned outages.

Ontario Plants

        All the power output from the Ontario plants is sold to Ontario Electricity Financial Corporation under long-term PPAs with expiry dates ranging from 2012 to 2020. The Ontario plants reported operating margin of $46.0 million for the year ended December 31, 2010 compared to $52.7 million in 2009. The decrease was primarily due to lower waste heat availability, higher prices in natural gas supply contracts and higher natural gas transportation costs partially offset by higher prices in power sales contracts and lower waste heat optimization costs.

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Revenue from Ontario plants

Years ended December 31 (millions of dollars)
  2010   2009  

Power

    136.4     138.3  

Enhancements

    1.4     1.1  

Gas diversions

    5.4     6.0  
           

    143.2     145.4  
           

        Revenues from the Ontario plants were lower for the year ended December 31, 2010 compared to 2009 due to lower waste heat availability partially offset by higher prices in power sales contracts. Revenues from waste heat were $6.4 million during the year ended December 31, 2010 compared to $15.4 million in 2009 as a result of lower throughput on TransCanada Corporation's Canadian Mainline, the natural gas transmission line through Northern Ontario. At throughput levels experienced in 2010, at times almost no compression was needed to move the natural gas resulting in no waste heat. Future throughput on the TransCanada Canadian Mainline will continue to be subject to supply and demand variances, however, the Partnership believes the decline in waste heat levelled off in 2010 and the economy has started a slow recovery. TransCanada's most recent projections of volumes for the next five years reflect a moderate increase in volumes in part attributable to TransCanada's plans to divert volumes from its Great Lakes Gas Transmission pipeline to the Canadian Mainline.

        Power output from the Ontario plants for the year ended December 31, 2010 was 54 gigawatt hours (GWh) lower year-over-year as a result of lower waste heat availability and an outage at Tunis in the third quarter of 2010, partially offset by an outage at Calstock in third quarter of 2009. Availability was higher at the Ontario plants during the year ended December 31, 2010 compared to 2009 as a result of the Calstock outage in 2009.

Williams Lake

        Revenues at Williams Lake consist of firm energy sales including cost recovery components under the PPA with British Columbia Hydro and Power Authority (BC Hydro) expiring in 2018. The amount of firm energy sold to BC Hydro on an annual basis is fixed at 445 GWh, except in years when major overhauls are performed (approximately every five years). Revenues remain constant in major overhaul years due to higher firm energy pricing and the firm energy commitment to BC Hydro is reduced to 401 GWh. Cost recovery components are escalated annually for inflation. Generation in excess of the firm energy requirements can be sold to BC Hydro under the power sales contract. In 2010, the Partnership sold the excess energy from Williams Lake to a third party at prices that were higher than under the power sales contract.

        Generation during the year ended December 31, 2010 was higher than in 2009 due to a temporary outage in 2009 initiated by the Partnership and the PPA counterparty resulting from reduced production from the plant's major wood waste suppliers. Under the terms of the Williams Lake PPA, the Partnership continued to receive energy payments while the plant was offline.

        Included in revenue are excess energy sales for the year ended December 31, 2010 of $4.0 million compared with $6.4 million in 2009. Excess energy sales were lower in 2010 due to lower pricing for the excess energy.

        Operating margin from Williams Lake was $24.3 million for the year ended December 31, 2010 compared to $27.8 million in 2009. The decrease was due to lower pricing on excess energy sales.

Schedule V-14


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BC Hydroelectric Plants

        Mamquam and Moresby Lake have long-term PPAs with BC Hydro that expire in 2027 and 2022, respectively. The PPAs consist of a fixed energy component per megawatt hour (MWh) up to certain output thresholds, an operations and maintenance component adjusted annually for inflation and a reimbursable cost component. All electricity generated at Mamquam and substantially all electricity generated at Moresby Lake is sold to BC Hydro. A small amount of electricity from Moresby Lake is sold to two local customers.

        Operating margin at the BC hydroelectric plants was $14.8 million for the year ended December 31, 2010 compared to $11.1 million in 2009. The increase in operating margin, as well as the increases in revenue and generation, was due to higher water volumes at the plants.

Northwest US Plants

        Manchief has two separate tolling agreements covering the sale of capacity and incremental energy to Public Service Company of Colorado (PSCo) that expire in 2022. PSCo controls the dispatch of electricity from Manchief, including start-ups, shut-downs and generation loading levels. Capacity payments are generally unaffected by output levels but vary depending upon changes in plant availability. Capacity payments will be approximately 15% lower starting in May 2012. PSCo pays for incremental energy generated at the plant based upon a fixed price per MWh, escalated annually for inflation. PSCo also pays for turbine start-up fees, heat rate adjustments and natural gas transportation charges. Operating margin was $19.3 million for the year ended December 31, 2010 compared to $22.4 million in 2009. The decrease was the result of higher dispatch of the plant in 2009 due to outages at other plants in the region and lower prices on the foreign exchange contracts that settled in 2010.

        The Partnership's portion of the capacity of Frederickson has been sold under tolling arrangements expiring in 2022 to three Washington State public utility districts (the PUDs). The remaining interest in Frederickson is held by Puget Sound Energy, Inc. which works cooperatively with the PUDs to economically dispatch Frederickson. The PUDs pay capacity and fixed operating and maintenance charges as well as all fuel related costs and commercial start-up costs. Operating margin from Frederickson was $13.5 million for year ended December 31, 2010 compared to $13.2 million in 2009. The increase in operating margin was the result of lower operating and maintenance costs partially offset by lower prices on foreign exchange contracts that settled in 2010.

        Greeley provides all of its electrical output to PSCo under a PPA which expires in 2013. PSCo pays a monthly capacity payment and an energy payment pursuant to the PPA. Greeley sells hot water to the University of Northern Colorado (UNC) pursuant to a Thermal Supply Agreement which expires in August 2013. Under the agreement, Greeley is obligated to deliver for sale to UNC only such heat energy as is generated during the production of electrical capacity and energy for sale to PSCo. Operating margin from Greeley was $1.4 million for the year ended December 31, 2010 consistent with $1.1 million in 2009.

        Availability for the Northwest US plants for the year ended December 31, 2010 was consistent with 2009. Generation was lower due to lower dispatch of Manchief in 2010 due to outages at other plants in the region in 2009.

California Plants

        The three US Naval facilities (the Naval facilities) sell power to San Diego Gas and Electric Company (SDG&E) under long-term PPAs which expire in 2019, except for a 4 MW steam turbine at North Island which sells power to the United States Navy (the Navy) under its SPA which expires in 2018. The price paid under the PPAs includes a capacity payment and an energy payment based on

Schedule V-15


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SDG&E's full short run avoided cost (SRAC). Each of the Naval facilities sells steam to the Navy pursuant to long-term SPAs, each of which expires in February 2018. The SPAs also give the Navy a right to purchase electrical energy from the Naval facilities at prices comparable to those under the PPAs. The Navy has an obligation to consume enough thermal energy for the Naval facilities to maintain their qualifying facility (QF) status. The Navy pays a combination of steam commodity charges, fixed charges and water cost pass through provisions. Steam pricing is linked to the cost of natural gas and SDG&E's SRAC by an energy sharing formula. Operating margin from the Naval facilities was $23.6 million for the year ended December 31, 2010 compared to $21.5 million in 2009. The increase was due to the higher availability and dispatch of Naval Station due to planned outages for inspections in February 2009 and at North Island due to outages for the turbine replacement project in 2009 partially offset by lower prices on the foreign exchange contracts that settled in 2010.

        All power output from Oxnard is sold to SCE under a PPA which expires in 2020. The price paid under the PPA includes a capacity payment and an energy payment based on SCE's SRAC. Steam from Oxnard is used to provide refrigeration services to Boskovich Farms, a food processing and cold storage facility, thereby maintaining Oxnard's QF status. Operating margin from Oxnard was $4.8 million for the year ended December 31, 2010 compared to $8.3 million in 2009. The decrease was the result of lower availability and dispatch as the plant was offline for the turbine replacement project in 2010 and lower prices on the foreign exchange contracts that settled in 2010. For accounting purposes the PPA with SCE is considered a direct financing lease and a portion of the PPA payments are considered principal repayments. During the year ended December 31, 2010, $2.8 million of PPA payments were applied against the long-term receivable from SCE compared to $1.9 million in 2010. Revenues were higher at Oxnard in 2010 compared to 2009 as the completion of the turbine upgrade has been considered to be sold to SCE in exchange for a long-term receivable.

        Availability and generation for the California plants for the year ended December 31, 2010 was consistent with 2009.

        Revenues and operating margins for the California facilities are seasonal. Approximately 75% of capacity revenue at the Naval facilities is earned during the summer peak demand months. For all the California plants, performance bonuses can be earned during these months if forced outage rates are below 15%.

Curtis Palmer

        Output from Curtis Palmer is sold to Niagara Mohawk Power Corporation (Niagara Mohawk) under a PPA which expires the earlier of 2027 and the delivery to Niagara Mohawk of a cumulative 10,000 GWh of electricity. The PPA sets out eleven pricing blocks over the contract term for electricity sold to Niagara Mohawk and the price is dependent on the cumulative GWh of electricity delivered. Over the remaining term of the PPA, the price increases by US$10/MWh with each additional 1,000 GWh of electricity delivered. The next cumulative GWh threshold is expected to be reached in the fourth quarter of 2011.

        Operating margin from Curtis Palmer was $31.4 million for the year ended December 31, 2010 compared to $36.3 million in 2009. The decrease was due to lower generation as a result of lower water volumes at the plant and lower prices on the foreign exchange contracts that settled in 2010 partially offset by an overhaul completed in June 2009.

Northeast US Natural Gas Plants

        Morris sells a combination of steam and power to Equistar under an energy services agreement (ESA) that expires in October 2023. Pursuant to the Morris ESA, Equistar pays tiered energy payments based on electricity and steam delivered to a maximum of 77 MW and 720 million pounds of steam per hour and adjusted for monthly natural gas prices. Based on the energy payment formula, there is a

Schedule V-16


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small portion of energy costs that are not recovered through the energy payments and this non-recoverable amount fluctuates with the price of natural gas. Equistar also pays capacity fees, comprised of both a non-escalating fixed fee that expires in October 2013 and a variable fee that escalates with materials and labour indices and expires in 2023. The non-escalating capacity payment is fixed at $8.3 million (US$8.3 million) per year. Morris has a PPA with Exelon Generation Company, LLC (Exelon) covering 100 MW of electrical capacity. Exelon pays a capacity charge that varies based on the time of year together with an energy charge based on amount of energy dispatched. The annual capacity revenue earned under the PPA with Exelon has averaged just over US$6 million per year, including bonus payments for peak availability that exceeds 98%. The Exelon PPA expires in April 2011 after which Morris has participated in capacity auctions in the PJM market to April 2014. Auction prices are lower than the Exelon contract and as a result capacity revenue is expected to be approximately $2 million lower in 2011 and $4 million to $5 million lower in 2012 and 2013 compared to 2010.

        Operating margin from Morris, was $14.9 million for the year ended December 31, 2010 compared to $13.8 million in 2009. The increase was the result of lower maintenance and operating costs partially offset by lower prices on foreign exchange contracts that settled in 2010.

        Kenilworth sells electrical energy and steam to Schering-Plough Corporation (Schering) under an ESA that expires in July 2012. Pursuant to the ESA, Schering pays an energy rate that escalates annually. Any power produced in excess of Schering's requirements is sold to Public Service Enterprise Group Incorporated at current market prices. Revenues from steam are calculated as a function of the delivered cost of fuel. The ESA allows natural gas costs to be passed on to Schering when natural gas prices exceed a set price. Operating margin from Kenilworth was $2.5 million for the year ended December 31, 2010 compared to $4.6 million in 2009. The decrease was due to lower natural gas prices and lower prices on the foreign exchange contracts that settled in 2010.

North Carolina Plants

        The North Carolina plants provide all of their electrical output to Progress. The PPAs with Progress expired in December 2009. The NCUC ruled on four fundamental issues in the arbitration process initiated by the Partnership and the Partnership and Progress continue to negotiate the terms of new PPAs (see Significant Events—Arbitration ruling for North Carolina plants and completion of enhancement project). The NCUC has required that Progress continue to purchase electrical output from the North Carolina plants pursuant to the terms of the expired PPAs until new PPAs are entered. During this interim period, the price paid includes capacity payments and energy payments that reflect the price paid for coal and cycling charges. If this pricing does not result in a dispatch order for the facility, the Partnership has the right, but not the obligation, to bid an alternate price based upon its own pricing strategies to obtain a dispatch order. Southport sells steam pursuant to a SPA which expires in December 2014. Roxboro does not currently have a SPA. Both the facilities are QF certified.

        The North Carolina plants reported operating margin losses of $7.3 million for the year ended December 31, 2010 compared to $10.0 million in 2009. The decreases in the losses were due to lower maintenance costs as a result of an outage at Roxboro in 2009 and higher dispatch of the plants in 2010. Partially offsetting these increases was lower revenue at Southport due to lower steam demand and lower capacity payments due to an outage in March 2010.

Fair value changes

        Unrealized gains on foreign exchange contracts were $7.8 million for the year ended December 31, 2010 compared to $58.8 million in 2009. The changes in fair value were primarily due to changes in the forward prices for US dollars relative to Canadian dollars which decreased $0.039 for the year ended December 31, 2010 compared to $0.144 in 2009.

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        The Partnership recorded fair value losses on natural gas supply contracts of $11.4 million for the year ended December 31, 2010 compared to $52.4 million in 2009. The changes in the fair value of the natural gas contracts were primarily due to changes in natural gas forward prices. Alberta forward natural gas prices decreased $1.65 per gigajoule (GJ) for the year ended December 31, 2010 compared to $1.02 per GJ in 2009. On July 31, 2009, the Partnership designated certain of its natural gas supply contracts as hedges. Net losses of $59.1 million relating to these contracts were recorded in other comprehensive income in 2010 compared to $8.9 million in 2009.


COST OF FUEL

Years ended December 31
  2010   2009  
(millions of dollars except average cost per MWh)
   
 

Ontario plants

             
 

Natural gas

    76.1     69.7  
 

Waste heat

    0.7     3.4  
 

Wood waste

    3.9     3.0  
           

    80.7     76.1  

Williams Lake—wood waste

   
7.7
   
5.7
 

Northwest US plants—natural gas

   
10.7
   
11.7
 

California plants—natural gas

   
47.9
   
47.5
 

Northeast US natural gas plants—natural gas(1)

   
46.7
   
61.1
 

North Carolina plants—wood waste, tire-derived fuel & coal

   
25.6
   
16.9
 

Fair value changes on natural gas contracts

   
11.4
   
52.4
 
           

    230.7     271.4  
           

(1)
Restated to reflect the operations of Castleton as discontinued operations. Castleton was sold in May 2009.

        Fuel costs, which are the Partnership's most significant cost of operations, include commodity costs, transportation costs and fair value changes on natural gas supply contracts.

        For the year ended December 31, 2010, fuel costs, excluding fair value changes on natural gas contracts, were $219.3 million compared to $219.0 million in 2009.

        Fuel costs at the Ontario plants for the year ended December 31, 2010 were $80.7 million compared to $76.1 million in 2009. The increase was primarily due to higher prices in natural gas supply contracts and higher natural gas transportation costs partially offset by lower waste heat optimization costs. During the third quarter of 2010, the Partnership negotiated to change the delivery point for natural gas supplied under contract to Nipigon and Tunis. The change in delivery point is expected to reduce natural gas transportation costs by approximately $0.7 million over the remaining terms of the natural gas contracts.

        Williams Lake incurred fuel costs of $7.7 million for the year ended December 31, 2010 compared to $5.7 million in 2009. The increase was primarily the result of a temporary outage in 2009 due to reduced production from the plant's major wood waste suppliers.

        The Northwest US plants incurred fuel costs of $10.7 million for the year ended December 31, 2010 compared to $11.7 million in 2009. The decrease was due to a weaker US dollar relative to the Canadian dollar.

Schedule V-18


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        Fuel costs at the California facilities were $47.9 million for the year ended December 31, 2010 compared to $47.5 million in 2009. The increase was due to higher natural gas prices in California and higher steam production partially offset by a weaker US dollar relative to the Canadian dollar.

        The Northeast US natural gas plants incurred fuel costs of $46.7 million for the year ended December 31, 2010, compared to $61.1 million in 2009. The decrease was primarily due to lower natural gas supply prices at Kenilworth and a weaker US dollar relative to the Canadian dollar.

        The North Carolina plants incurred fuel costs of $25.6 million for the year ended December 31, 2010 compared to $16.9 million in 2009. The increase was the result of higher dispatch partially offset by a lower cost fuel blend that incorporated more wood waste and a weaker US dollar relative to the Canadian dollar.

        The Curtis Palmer, Mamquam and Moresby Lake hydroelectric plants do not have fuel costs.


OPERATING AND MAINTENANCE EXPENSE

Years ended December 31 (millions of dollars)
  2010   2009  

Ontario plants

    16.5     16.6  

Williams Lake

    10.2     9.4  

BC hydroelectric plants

    5.0     4.6  

Northwest US plants

    12.8     14.7  

California plants

    36.3     19.7  

Curtis Palmer

    5.4     5.8  

Northeast US Gas plants(1)

    8.7     11.1  

North Carolina plants

    17.9     20.4  

PERC management expenses

    1.4     1.1  
           

    114.2     103.4  
           

(1)
Restated to reflect the operations of Castleton as discontinued operations. Castleton was sold in May 2009.

        Operating and maintenance expenses include payments to the Manager and third parties for the operation and routine maintenance of the plants. Fees paid to the Manager are based on fixed charges adjusted annually for inflation for the Canadian plants, Curtis Palmer and Manchief, and a flow through of costs for the remaining US plants. Operating and maintenance expenses were $114.2 million for the year ended December 31, 2010 compared to $103.4 million in 2009. The increase was due to completion of the turbine replacement at Oxnard partially offset by lower maintenance costs at the North Carolina facilities and a weaker US dollar relative to the Canadian dollar.

        During the second quarter of 2010, the Partnership completed the repowering of the natural gas turbine at Oxnard with a goal to improve plant efficiency and reliability. For accounting purposes Oxnard was considered to be sold to SCE when the PPA was entered in 1990. Accordingly, the replacement of the Oxnard turbine has been expensed. At the same time revenue has been recognized as the turbine upgrade has been considered to be sold to SCE in exchange for a long-term receivable. Project costs incurred during the year ended December 31, 2010 were $14.4 million.

Schedule V-19


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DEPRECIATION, AMORTIZATION AND ACCRETION

Years ended December 31 (millions of dollars)
  2010   2009  

Depreciation of property, plant and equipment

    69.6     65.0  

Accretion of asset retirement obligations

    2.9     1.9  

Amortization of PPAs

    25.4     27.8  

Other amortization

    0.4     (1.4 )
           

    98.3     93.3  
           

        Depreciation, amortization and accretion expense for the year ended December 31, 2010 was $98.3 million compared to $93.3 million in 2009. The increase in depreciation charges for the year was mainly due to the completion of upgrades at the North Carolina facilities in 2010.


MANAGEMENT AND ADMINISTRATION

Years ended December 31 (millions of dollars)
  2010   2009  

Base fee

    0.9     1.1  

Enhancement fee

    0.1     0.2  

General and administrative costs

    12.9     13.9  
           

    13.9     15.2  
           

        Management and administration costs, which include fees payable to the Manager and general and administrative costs, were $13.9 million for the year ended December 31, 2010 compared to $15.2 million in 2009. The decrease was primarily due to the reversal of a $2.1 million allowance for doubtful accounts provision on a receivable from Equistar partially offset by higher legal and consulting costs.


FINANCIAL CHARGES AND OTHER, NET

Years ended December 31 (millions of dollars)
  2010   2009  

Interest on long-term debt

    39.0     42.6  

Foreign exchange losses

    0.3     1.0  

Interest on Equistar receivable

    (1.8 )    

Losses from equity investment

        3.1  

Dividend income

        (1.1 )

Other

    2.6     0.8  
           

    40.1     46.4  
           

        Financial charges and other expenses were $40.1 million for the year ended December 31, 2010 compared to $46.4 million in 2009. The decrease was primarily due to the impact of a weaker US dollar relative to the Canadian dollar on US dollar interest expenses and interest income of $1.8 million from Equistar.

        Losses from equity investment were from the Partnership's common ownership interest in Primary Energy Recycling Holdings LLC (PERH), which was accounted for on the equity basis up to August 24, 2009 and on a cost basis thereafter.


INCOME TAX RECOVERY

        Income tax recovery was $9.4 million for the year ended December 31, 2010, consistent with $8.9 million in 2009. The taxable income of the Partnership was taxed in the hands of unitholders up to

Schedule V-20


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the end of 2010. Starting in 2011, taxes will be applied at the Partnership level as changes to Canadian tax legislation became effective.

        The Partnership does not expect to make any material cash income tax payments until 2015 or 2016 in both Canada and the US, due to tax attributes consisting primarily of tax losses and undepreciated capital cost pools available to the Partnership to deduct against future taxable income.


PREFERRED SHARE DIVIDENDS OF A SUBSIDIARY COMPANY

        A subsidiary of the Partnership has issued $125.0 million of Series 1 preferred shares, which pay dividends at a rate of 4.85% per annum, and $100.0 million Series 2 preferred shares, which pay dividends at a rate of 7.0% until their reset date on December 31, 2014. For the year ended December 31, 2010, dividends of $13.1 million were paid to shareholders and net income tax expenses of $1.0 million were recorded. Part VI.1 tax is paid at a rate of 40% of the dividends and a deduction from Part I tax is available for payment of Part VI.1 tax, which results in a tax benefit approximately equal to the Part VI.1 tax paid. The subsidiary expects to realize the benefit of the deduction starting in 2011.


LIQUIDITY AND CAPITAL RESOURCES

Distributions

        The Partnership makes monthly cash distributions to its Unitholders in accordance with the Partnership Agreement and subject to Board approval. Cash distributions are made in respect of each month in each year to unitholders of record on the last day of such month. Payments are made in the month following each record date. Distributions are prohibited by certain loan agreement covenants if an uncured default exists. Additionally, distributions are prohibited if declaration or payment of dividends on the preferred shares is in arrears. Up to the end of 2010, a portion of cash distributions were taxable to unitholders in the year received. Starting in 2011, taxes will be applied at the Partnership level and distributions will be taxable to unitholders in the year received as if they were taxable dividends, as changes to Canadian tax legislation became effective.

        In the second quarter of 2009, the Partnership reduced its distribution from $0.63 per quarter to $0.44 per quarter. In the fourth quarter of 2009, the Partnership announced a change in the frequency of its distributions to monthly from quarterly and the launch of distribution reinvestment programs.

        When cash provided by operating activities exceeds distributions and maintenance capital expenditures, the Partnership utilizes the difference to stabilize future distributions, to finance growth capital expenditures and to make debt repayments. When cash provided by operating activities is less than distributions and maintenance capital expenditures, the Partnership utilizes available cash balances and short-term financing to cover the shortfall. The ability of the Partnership to sustain current cash flow is subject to the Partnership finding cash accretive investments to replace expected future declines

Schedule V-21


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in cash flow from contracts that expire and which may not be replaced with contracts under similar terms.

Years ended December 31 (millions of dollars except payout ratio)
  2010   2009(2)  

Distributions

    96.9     105.2  

Cash provided by operating activities of continuing operations

    117.8     134.5  

Net income from continuing operations

    30.5     57.8  

Payout ratio(1)

   
89

%
 
86

%

Dividends from PERH

   
   
1.3
 

Additions to property, plant and equipment

    28.3     100.7  

Excess of cash provided by operating activities of continuing operations over distributions

   
20.9
   
29.3
 

Shortfall of net income from continuing operating over distributions

    (66.4 )   (47.4 )

(1)
Payout ratio is cash distributions divided by cash provided by operating activities of continuing operations excluding changes in working capital less maintenance capital expenditures. See Non-GAAP Measures.

(2)
The Partnership made an immaterial adjustment to the 2009 financial statements to reflect the reclassification of $5.2 million of property, plant and equipment to inventory resulting in a decrease in cash provided by operating activities and capital expenditures. There was no impact to net earnings resulting from this adjustment.

        Cash provided by operating activities of continuing operations exceeded distributions by $20.9 million for the year ended December 31, 2010. The Partnership also incurred capital expenditures of $28.3 million during the year ended December 31, 2010. The cash shortfall between distributions plus capital expenditures and cash provided by operating activities of continuing operations has been funded with proceeds from the distribution reinvestment program and draws on the credit facilities. The financing needs of the Partnership will be influenced by, among other factors, its capital spending in 2011 and potential acquisitions.

        The Partnership expects cash provided by operating activities (excluding changes in working capital requirements) to be higher in 2011 compared to 2010 as further outlined under Outlook, subject to variable factors including those discussed in our forward looking statements at the end of this MD&A. In addition, the Partnership expects capital expenditures in 2011, excluding the investments in the North Carolina, to be approximately $7 million to $9 million higher than maintenance capital expenditures in 2010 as outlined under Capital Expenditures. However, the Partnership expects total capital expenditures to be lower in 2011 as the Partnership completed a majority of the North Carolina enhancements in 2010.

        While the Partnership anticipates seasonal fluctuations in its working capital, it does not expect a significant increase in working capital requirements over the long term for existing operations. Year end 2011 working capital requirements are expected to remain at levels consistent with December 31, 2010 balances, with higher balances in the second and third quarters of 2011 and lower balances in the first and fourth quarters of 2011.

        Net income is not necessarily comparable to distributions as net income includes items such as changes in the fair value of derivative instruments. Aside from these items, management expects that distributions will exceed net income in 2011. Accordingly, a portion of the distributions represent a return of capital. To date, and subject to ensuring adequate liquidity, the Partnership has chosen to make distributions that include a return of capital.

Schedule V-22


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        To the extent there is a shortfall between the Partnership's cash provided by operating activities and distributions and capital expenditures, the Partnership has available to it two revolving credit facilities, each of $100.0 million expiring in September 2012 and October 2012 and a third revolving credit facility of $125.0 million expiring in June 2012. The Partnership also has two demand facilities of $20.0 million and US$20.0 million respectively. Alternatively, in the case of major investments of capital, the Partnership may obtain new capital from external markets at the time of the required investment, utilizing its $600 million shelf prospectus which expires in August 2012.

        Beginning in 2006, the Partnership deferred utilizing elective deductions, including capital cost allowance, for Canadian income tax purposes in response to the Partnership's Canadian operations becoming taxable in 2011. As a result, the 2010 taxable amount of cash distributions per unit increased from $0.09, had the Partnership claimed full elective deductions in the year, to the actual amount of $0.57 per unit. The use of elective deductions for Canadian income tax purposes would not benefit a tax deferred investor whereas the deferral of these elective deductions is expected to benefit all investors beginning in 2011.

        The following table summarizes the tax pools the Partnership has available to deduct against future taxable income. Tax pools are comprised primarily of undepreciated capital costs and accumulated tax losses.

As at December 31 (millions of dollars)
  2010   2009  

Canadian tax pools

    401.3     376.7  

US tax pools (US$)

    851.7     867.0  


Capital expenditures

        Capital expenditures are primarily comprised of maintenance capital and additions to, or replacements of, equipment required to maintain or increase current output capacity. Major overhauls are performed periodically at each of the plants based on the number of operating hours and type of equipment. Major overhauls at the Ontario, Kenilworth, Morris and Naval plants are performed approximately every 25,000 operating hours or roughly every three years for hot section refurbishments on the gas turbines to approximately 50,000 operating hours or every six years for turbine overhauls. As a result of SRAC changes implemented in 2009, the Partnership may choose to dispatch the Naval facilities only during peak periods, thus increasing the interval between major overhauls. Hot section refurbishments and turbine overhauls are performed at Frederickson and Manchief at the same number of operating hours, however these plants are normally dispatched only during periods of peak power demand reducing operating hours each year and consequently increasing the interval between major overhauls. Similarly, major overhauls are performed at Greeley depending on plant usage. It is expected that the heat recovery steam generators will require re-tubing approximately once in 20 years.

        Major overhauls are completed at the Williams Lake, Calstock and North Carolina plants approximately every five to eight years and are condition based.

        Maintenance capital expenditures for the hydroelectric facilities are expected to be at longer intervals and are condition based.

Schedule V-23


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        Capital expenditures for the year ended December 31, 2010 totalled $28.3 million, compared with $100.7 million in 2009. Capital spending for the year ended December 31, 2010 included spending for the enhancement of the Southport and Roxboro plants.

Years ended December 31 (millions of dollars)
  2010   2009  

Maintenance capital expenditures

    16.8     20.0  

North Carolina enhancement project

    11.5     65.0  

North Island turbine replacement project

        15.7  
           

    28.3     100.7  
           

        The Partnership has invested $89.8 million (US$81.7 million) to December 31, 2010 for the enhancement of the Southport and Roxboro plants to reduce environmental emissions and improve their economic performance. The enhancements at Roxboro and two units at Southport were completed in 2009 and 2010. The Partnership plans to invest an additional $5 million (US$5 million) in 2011 primarily for the construction of access roads at Southport and final testing.

        The Partnership expects that over its five year planning cycle maintenance capital expenditures will average $20 million to $22 million annually for its existing facilities. Aside from the completion of the enhancements at Southport, the Partnership expects maintenance capital spending to be approximately $24 million to $26 million in 2011, higher than expectations for its five year planning cycle as certain projects have been deferred to 2011 from 2010.


Financing

        The following table summarizes the long-term debt of the Partnership.

As at December 31 (millions of dollars)
  2010   2009  

Senior unsecured notes, due 2036

    210.0     210.0  

Senior unsecured notes (US$415.0) due 2014 to 2019

    412.8     436.1  

Secured term loan

        1.4  

Revolving credit facilities

    86.1     78.3  
           

    708.9     725.8  
           

        The Partnership's debt to total capitalization ratio as at December 31, 2010 increased to 53% from 49% at December 31, 2009 primarily due to declines in the fair value of natural gas contracts and distributions paid in excess of net income. The debt to total capitalization ratio is calculated as follows:

Debt to total capitalization ratio =   Debt (short-term debt + long-term debt)

Debt + preferred shares + partners' equity

        Under the terms of its debt agreements, the Partnership must maintain a debt to capitalization ratio of not more than 65% at the end of each fiscal quarter. During the year ended December 31, 2010, the Partnership had net drawings of $8.1 million on its revolving credit facilities. Draws on the credit facilities were used to fund the North Carolina and Oxnard projects. Under the revolving credit facilities, in the event the Partnership is assigned both a rating of less than BBB+ by Standard and Poors (S&P) and a rating of less than BBB(high) by DBRS Limited (DBRS), the Partnership also would be required to maintain a ratio of EBITDA (earnings before interest, income taxes, depreciation and amortization as defined in the credit facilities) to interest expense of not less than 2.5 to 1, measured quarterly. Although the Partnership is not required to meet the EBITDA to interest ratio, the ratio was 4.1 as at December 31, 2010. The Partnership was compliant with all of its debt covenants under its debt agreements for the years ended December 31, 2010 and 2009.

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        If an event of default occurs and continues under the Partnership's credit facilities, the Partnership may not declare, make or pay distributions (subject to certain limited exceptions).

        S&P reduced the credit rating assigned to the Partnership to BBB from BBB+ during the third quarter of 2010. S&P has discontinued issuing stability ratings. DBRS has assigned the Partnership a BBB(high) debt rating and STA-2(low) stability rating. DBRS placed the debt rating under review with negative implications at the time of the announcement of the strategic review process.

        The BBB debt rating by S&P is the fourth highest rating out of 10 rating categories. According to S&P, an obligor rated BBB has adequate capacity to meet its financial commitments. The BBB rating is DBRS' fourth highest of 10 categories. DBRS' BBB(high) rating designates the Partnership's debt as being of satisfactory credit quality with the protection of interest and principal still substantial. The high classification shows the relative standing within the major rating categories. The review with negative implications by DBRS highlights the potential that the long-term ratings may be lowered.

        Having an investment grade credit rating improves the Partnership's ability to re-finance existing debt as it matures and to access cost competitive capital for future growth.

        The STA-2 (low) stability rating by DBRS is the second highest of seven categories in their rating system for income fund stability. DBRS further subcategorizes each rating by the designation of "high", "middle" and "low" to indicate where an entity falls within the rating category.


Financial market liquidity

        Volatility in the Canadian and US financial markets may adversely impact the Partnership's access to capital. The Partnership has a sufficient liquidity position with revolving credit facilities of $325 million and a demand credit facility of $20.0 million with Canadian tier 1 banks. The Partnership also has a demand credit facility of US$20.0 million with a US tier 1 bank. Principal repayments on the Partnership's long-term debt facilities are as follows:

Year
  Principal repayment
(millions of dollars)
 

2012

    86.1  

2014

    189.0  

2017

    149.2  

2019

    74.6  

2036

    210.0  

        Uncertainty in global financial markets and, in particular, the Canadian and US financial markets may adversely affect the Partnership's ability to arrange permanent long-term financing for acquisitions, for significant capital expenditures and potentially to refinance indebtedness under the credit facilities outstanding at their maturity dates. This may also affect the Partnership's credit ratings.

        The Partnership continues to monitor changes in counterparty credit quality. Counterparties to the Partnership's PPAs are primarily investment grade, with 94% of operating margin from counterparties with a credit rating of A- or higher by S&P and include government agencies and utilities. The balance of the PPAs, other than with Equistar, are with enterprises with investment grade credit ratings of at least BBB- by S&P. The A credit rating is the third highest rating and the BBB credit rating is the fourth highest rating out of 10 rating categories. The minus sign shows the relative standing within the major rating categories. Equistar has a non-investment grade credit rating and underwent and emerged from a reorganization under Chapter 11 of the US Bankruptcy Code in 2009 and 2010. As well, a significant counterparty risk exists with wood waste suppliers given current market conditions, both in terms of slowing demand in the housing industry and its impact on the forestry industry in Canada as well as potential constraints wood waste suppliers may face in raising new capital. The Partnership has been actively seeking new sources of wood waste supply.

Schedule V-25


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TRANSACTIONS WITH RELATED PARTIES

Years ended December 31 (millions of dollars)
  2010   2009  

Transactions with CPC(1)

             

Revenue—Frederickson duct firing capacity fees

    0.1     0.1  

Cost of fuel—Greeley natural gas contract

    1.5     2.6  

Operating and maintenance expense

    47.5     50.5  

Management and administration

             
 

Base fee

    0.9     1.1  
 

Enhancement fee

    0.1     0.2  
 

General and administrative costs

    8.4     8.0  
           

    9.4     9.3  
           

Acquisition and divestiture fees

        0.2  

Distributions

    29.1     32.2  

Transactions of discontinued operations

             
 

Cost of fuel—natural gas demand charge

        1.1  
 

Operating and maintenance expense

        1.4  

(1)
Prior to July 1, 2009, EPCOR.

        In operating the Partnership's 20 power plants, the Partnership and CPC (and prior to July 1, 2009, EPCOR) engage in a number of related party transactions which are in the normal course of business. These transactions are based on contracts and many of the fees are escalated by inflation. The table above summarizes the amounts included in the calculation of net income for the years ended December 31, 2010 and 2009. Operating and maintenance expenses were $47.5 million for the year ended December 31, 2010, compared with $50.5 million in 2009. The decrease was due to a weaker US dollar relative to the Canadian dollar.

        Operating and maintenance expense, cost of fuel, base fees and administration fees represent fees that are intended to reimburse CPC for the provision of operating and maintenance services and materials or commodities. Incentive and enhancement fees are intended to provide CPC with an incentive to maximize cash provided by operating activities that in turn are used to make distributions. Acquisition fees are intended to both reimburse CPC for its costs associated with acquiring and integrating new assets and to provide CPC with an incentive to grow the Partnership and increase its cash flows.

        During the year ended December 31, 2010, the Partnership made cash distributions to CPC (and prior to June 30, 2009, EPCOR) in the amount proportionate to its ownership interest. At December 31, 2010, CPC owned 29.6% of the Partnership's units (30.5% at December 31, 2009).

Schedule V-26


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COMMITMENTS AND CONTINGENCIES

        The Partnership's future purchase and debt repayment obligations, estimated based on existing contract terms, estimated inflation and foreign exchange rates as at December 31, 2010, are as follows:


Commitments

Years ended December 31

(millions of dollars)
  Note   2011   2012   2013   2014   2015   Later years  

Natural gas purchase contracts

    (1 )   51.9     53.7     43.9     47.2     50.7     53.6  

Natural gas transportation contracts

    (2 )   12.9     10.4     10.6     10.2     7.6     15.6  

Operating and maintenance contracts

    (3 )   27.5     28.1     28.6     29.2     29.8     46.0  

Long-term debt

              86.1         189.0         433.8  

Interest payments on long-term debt

          39.5     39.1     36.9     32.2     25.7     291.5  
                                 

Total

          131.8     217.4     120.0     307.8     113.8     840.5  
                                 

(1)
Natural gas purchase contracts have expiry dates ranging from 2012 to 2016 with built-in escalators.

(2)
Natural gas transportation contracts are based on estimates subject to changes in regulated rates for transportation and have expiry dates ranging from 2011 to 2017.

(3)
Operating and maintenance contracts for the Ontario plants, Mamquam, Moresby Lake, Williams Lake, Curtis Palmer and Manchief are based on fixed fees escalated annually by inflation and have expiry terms ranging from 2017 to 2018. Operating and maintenance contracts for the remaining power plants flow-through expenses.

        The Partnership is legally required to remove a majority of its power generation facilities at the end of their useful lives. The Partnership estimates that the undiscounted amount of payments required to settle its asset retirement obligations is approximately $129.4 million, calculated using inflation rates ranging from 2.1% to 3.0%. The expected timing for settlement of the obligations is between 2020 and 2090. The majority of the payments to settle the obligations are expected to occur between 2022 and 2070.


OFF-BALANCE SHEET ARRANGEMENTS

        At December 31, 2010 the Partnership did not have any off balance sheet arrangements.


CRITICAL ACCOUNTING ESTIMATES AND SIGNIFICANT ACCOUNTING POLICIES

        Since a determination of many assets, liabilities, revenues and expenses is dependent on future events, the preparation of the Partnership's consolidated financial statements requires the use of estimates and assumptions which are made using careful judgment.


Useful lives of assets

        The useful lives of the Partnership's property, plant and equipment and PPA assets are estimated for purposes of determining depreciation and amortization expense, in determining asset retirement obligations and in testing for potential impairment of long-lived assets. The estimated useful lives of assets are determined based on judgment, current facts, past experience, designed physical life, potential technological obsolescence and contract periods.

Schedule V-27


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        The Partnership depreciates and amortizes its property, plant, equipment and PPA assets over their estimated useful lives. The Partnership amortizes its power generation plant and equipment, less estimated residual value, on a straight-line basis over their estimated remaining useful lives. Other equipment is capitalized and amortized over estimated service lives. PPAs are amortized on a straight line basis over the remaining lives of the contracts.


Fair values

        Fair values are estimated to measure asset retirement obligations, to measure impairment, if any, of long-lived assets and goodwill, to determine purchase price allocations and to value derivative instruments.

        Expected demolition, restoration and other related costs to settle the Partnership's asset retirement obligations are estimated and discounted at an appropriate credit-adjusted risk-free rate to determine the fair value of the asset retirement obligations.

        Undiscounted cash flows are used to test for asset impairment. If the carrying value of the asset is more than the undiscounted cash flows, an impairment loss is recognized to the extent the carrying value exceeds fair value. Management has assessed the impact of the NCUC Order (see Significant Events—Arbitration ruling for North Carolina plants and completion of enhancement project) and has determined that the current carrying amounts of the North Carolina assets were still recoverable.

        For determining purchase price allocations for business combinations, the Partnership is required to estimate the fair value of certain assets and liabilities. Goodwill arising on a business combination is tested for impairment at least annually or more frequently if events and circumstances indicate that a possible impairment may arise earlier. To test for impairment, the fair value of the reporting unit is compared to the carrying value, including goodwill, of the reporting unit. If the carrying value of the reporting unit exceeds its fair value, the fair value of the reporting unit's goodwill is compared with its carrying amount to measure the impairment loss, if any.

        Estimates of fair value for asset retirement obligations, purchase price allocations, long-lived asset and goodwill impairment testing are based on discounted cash flow techniques employing management's best estimates of future cash flows based on specific assumptions and using an appropriate discount rate.

        Fair values of derivative instruments including foreign exchange contracts and natural gas supply contracts are based on quoted market prices. Changes in fair values are recorded in revenue and cost of fuel in the income statement, in other comprehensive income and in derivative instruments asset/liability on the balance sheet.

        Because useful lives and fair values are used in determining potential impairments for each long-lived asset, it is not possible to provide a reasonable quantification of the range of these estimates that would be meaningful to readers.

        There have been no material changes in the valuation techniques used from prior periods.


CHANGES IN ACCOUNTING POLICIES

        There were no changes made to the Partnership's accounting policies during the year ended December 31, 2010.

Schedule V-28


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FUTURE ACCOUNTING STANDARDS

International Financial Reporting Standards

        Canadian reporting issuers are required to report under International Financial Reporting Standards (IFRS) effective January 1, 2011, including comparative figures for the prior year. In January 2008, a core team was established to develop a plan which will result in the Partnership's first interim report for 2011 being in compliance with IFRS.

        The diagnostic phase of the project was completed in April 2008. For each international standard, the primary differences from Canadian GAAP were identified and an initial assessment of the impact of the required changes for the purpose of prioritizing and assigning resources was made.

        The information obtained from the diagnostic phase was used to develop a detailed plan for convergence and implementation. The convergence and implementation work has five key sections: Financial Statement Adjustments, Financial Statements, Systems Updates, Policies and Internal Controls and Training.

Financial Statement Adjustments

        For each international standard, the Partnership determined the quantitative impacts to the financial statements, system requirements, accounting policy decisions and changes to internal controls and business policies. Preliminary accounting policy decisions were brought forward to the Audit Committee for their information as each standard was addressed and final accounting policy decisions for all standards in effect at the end of 2010 were made in the fourth quarter of 2010.

        The following areas have been identified as having the most impact on the financial statements of the Partnership:

IFRS 1—First Time Adoption of IFRS

        IFRS 1 provides first time adopters with a number of elections, exempting them from retrospectively adopting certain IFRS. The following elections are relevant to the Partnership:

Schedule V-29


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Property, plant and equipment (PP&E)

        PP&E is primarily impacted by IAS 16—Property, Plant and Equipment and IAS 23—Borrowing Costs. IFRS are different from Canadian GAAP in that certain costs on constructed PP&E such as training costs, overheads and borrowing costs in excess of the actual entity's cost of debt may not be capitalized. As most of the Partnership's assets were acquired and not self constructed, the impact of retrospectively adopting this aspect of IAS 16 will not be significant.

        IFRS are also more specific with respect to the level at which component accounting is required, requiring each component for which different depreciation methods or rates are appropriate to be accounted for separately. The appropriate components have been identified and the most significant difference from GAAP is that overhauls embedded within the initial carrying amount of a turbine must be treated as a separate component. As a result, depreciation is expected to increase by approximately $2 million per year initially, with smaller impacts in the future as the initial overhauls become fully depreciated.

        On transition, it is estimated that the cumulative impact of componentization and removal of disallowed costs will result in a reduction of approximately $37 million from the carrying amount of PP&E, with a corresponding reduction to Partners' equity of $37 million less the associated change in future income taxes.

Impairment of Assets

        IAS 36—Impairment of Assets requires a one-step approach using discounted cash flow techniques for asset impairment testing and measurement. Canadian GAAP's two-step approach requires the application of discounted cash flow techniques to measure the impairment amount, but only after the use of undiscounted cash flow analysis has indicated the existence of an impairment. The adoption of IAS 36 is expected to result in more frequent write downs since the carrying value of assets which are supported by undiscounted cash flows may be determined to be impaired when the future cash flows are discounted in accordance with the IFRS requirements. Unlike Canadian GAAP, previous impairment losses may be reversed or reduced if the circumstances which led to the impairment change.

        IAS 36 also requires that impairment testing be done on a cash-generating unit level, which for the Partnership will be at a plant basis. In addition, any goodwill amounts must be allocated to cash-generating units and included in the impairment test for each plant, whereas it is not allocated to plants under Canadian GAAP. Accordingly, this change may result in more frequent write downs of goodwill.

        The Partnership has assessed the fair value of all its facilities and expects the combined impact of asset impairments identified and fair value elections taken under IFRS 1 to be an decrease in long term assets of approximately $10 million to $15 million at December 31, 2010 and a corresponding decrease in Partners' equity of $10 million to $15 million less the associated change in future income taxes.

Leases

        The IFRS criteria for determining whether an arrangement contains a lease and if a lease is financing or operating are different than under Canadian GAAP. The Partnership has evaluated its PPAs under IFRIC 4 and IAS 17 and determined that ten of its PPAs contain operating leases. Classification as an operating lease will not have an impact on the balance sheet or income statement but will require additional note disclosure. The Partnership does not expect any of its PPAs to be classified as finance leases other than at Oxnard, which was considered a direct financing lease under Canadian GAAP.

Schedule V-30


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Asset retirement obligations

        IAS 37—Provisions, Contingent Liabilities and Contingent Assets requires asset retirement obligations to be discounted at a risk free rate, rather than the credit adjusted risk free rate required under Canadian GAAP. As a result the Partnership expects that asset retirement obligations and property, plant and equipment will increase by approximately $18 million and $12 million respectively on transition, with a reduction to Partners' equity of $6 million.

        In the fourth quarter of 2010, the Partnership completed the quantification of the opening financial statement adjustments resulting from the application of all currently effective IFRS, including financial instruments, foreign exchange and income taxes. The draft, preliminary anticipated transition adjustments, transition financial statements and accounting policy changes were presented to the Audit Committee in the fourth quarter of 2010, and analysis continues before they are finalized for the Partnership's first quarter financial reports in 2011.

Financial Statements

        There are a number of international standards which relate to financial statement presentation. Draft financial statements highlighting the disclosure and presentation requirements were reviewed by and discussed with the Audit Committee in the first quarter of 2009. The development of the financial statement presentation evolved throughout the project as the impacts of implementing the various standards were quantified. The Partnership identified those areas requiring additional disclosure and developed processes to capture the additional information. Draft financial statements for the six months ended June 30, 2010 were prepared in accordance with IFRS, with an opening statement of financial position as at January 1, 2010, the Partnership's date of transition. These preliminary financial statements were presented to the Audit Committee in November 2010.

Systems Updates

        Systems must be able to capture 2010 financial information under both the prevailing Canadian GAAP and IFRS to allow comparative reporting in 2011. The Partnership completed its system updates in the third quarter of 2009 and implemented parallel general ledgers and fixed asset systems to allow both IFRS and Canadian GAAP information to be captured in 2010. The processes and internal controls related to the capture and reporting of IFRS information are similar to those for Canadian GAAP.

Policies and Internal Controls

        In the determination of the financial statement adjustments, requirements for changes to the Partnership's policies and internal controls were identified and documented. The changes were not significant.

        The impact of IFRS on certain agreements, such as debt, shareholder and compensation agreements was assessed and the Partnership has not identified provisions within the agreements which would be negatively impacted by the differences identified to date.

        In the fourth quarter of 2010, the IFRS team worked with investor relations to prepare information for the rating analysts.

Training

        The Partnership recognizes that training at all levels is essential to a successful conversion and integration. Accounting staff have attended four training sessions with more planned to occur throughout the conversion process. The Board of Directors and Audit Committee have attended a

Schedule V-31


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training session and the Audit Committee receives regular updates on the conversion project. A comprehensive project update was provided to the Audit Committee in the fourth quarter of 2010.


DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

        As of December 31, 2010, management conducted an evaluation of the design and effectiveness of the Partnership's disclosure controls and procedures to provide reasonable assurance that material information relating to the Partnership is made known to management by others, particularly during the period in which the Partnership's annual filings are being prepared and that information required to be disclosed by the Partnership in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The evaluation took into consideration the Partnership's Disclosure Policy, the internal sub-certification process that has been implemented and the functioning of its Disclosure Committee. In addition, the evaluation covered the Partnership's processes, systems and capabilities relating to public disclosures and the identification and communication of material information. Based on that evaluation, the President (acting as Chief Executive Officer) and the Chief Financial Officer of the General Partner have concluded that the Partnership's disclosure controls and procedures are appropriately designed and effective.

        Also as of December 31, 2010, management conducted an evaluation of the design and effectiveness of internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Based on that evaluation, the President and the Chief Financial Officer have concluded that the Partnership's internal controls over financial reporting are appropriately designed and effective.

        These evaluations were conducted in accordance with the standards of the Committee of Sponsoring Organizations, a recognized control model, and the requirements of the Canadian Securities Administrators' National Instrument 52-109.

        There were no changes made to the Partnership's internal controls over financial reporting during the year ended December 31, 2010 that have materially affected or are reasonably likely to materially affect the Partnership's internal control over financial reporting.


FINANCIAL INSTRUMENTS

        The Partnership has various financial instruments that are classified for financial reporting purposes as "available for sale", "held for trading", "held to maturity", or "loans and receivables". Financial liabilities are classified as either "held for trading" or "other liabilities". Initially, all financial assets and financial liabilities are recorded on the balance sheet at fair value with subsequent measurement determined by the classification of each financial asset and liability.

        The Partnership classifies its cash and cash equivalents and current and non-current derivative instruments assets and liabilities as held for trading and measures them at fair value. Accounts receivable are classified as loans and receivables and accounts payable and distributions payable are classified as other financial liabilities and are measured at amortized cost. The fair values of accounts receivable, accounts payable and distributions payable are not materially different from their carrying amounts due to their short-term nature. The investment in PERH is classified as available for sale and the net investment in lease is classified as loans and receivables. The net investment in lease relates to the Oxnard PPA, which is considered a direct financing lease for accounting purposes.

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        The classification, carrying amounts and fair values of the Partnership's other financial instruments held are summarized as follows:

 
  Carrying amount    
 
As at December 31, 2010 (millions of dollars)
  Loans and
receivables
  Other
financial
liabilities
  Fair
value
 

Other assets—net investment in lease and long term receivables

    41.3         42.4  

Long-term debt (including current portion)

        (704.5 )   (697.7 )


Risk management and hedging activities

        The Partnership is exposed to changes in energy commodity prices, foreign currency exchange rates and interest rates. The Partnership uses various risk management techniques, including derivative instruments such as forward contracts, to reduce this exposure. These derivative instruments are recorded at fair value on the balance sheet unless the Partnership elects the fair value exemption for non-financial derivatives that are entered into and continue to be held for the purpose of receipt or delivery of a non-financial item in accordance with the Partnership's expected purchase, sale or usage requirements. The derivative instruments assets and liabilities used for risk management purposes are measured at fair value and consist of the following:

As at December 31, 2010 (millions of dollars)
  Natural gas
hedges
  Natural gas
non-hedges
  Foreign
exchange
non-hedges
  Total  

Total derivative instruments net assets (liabilities)

    (93.1 )   (3.0 )   33.2     (62.9 )


Natural gas derivatives designated as accounting hedges

        At December 31, 2010, the net fair value of energy derivative instruments designated and qualifying for hedge accounting was a net liability of $93.1 million and is included in derivative instruments assets and derivative instruments liabilities on the consolidated balance sheet. The net derivative liability is primarily due to a decrease in the forward Alberta natural gas prices relative to the derivative contract prices. Unrealized gains and losses for fair value changes on derivatives that qualify for hedge accounting are recorded in other comprehensive income and reclassified to net income as cost of fuel as appropriate when realized.


Derivatives not designated as accounting hedges

        At December 31, 2010, the net fair value of natural gas derivative instruments not designated as hedges for accounting was a net liability of $3.0 million and is included in derivative instruments assets and derivative instruments liabilities on the consolidated balance sheet. The net derivative liability is primarily due to a decrease in the forward Alberta natural gas prices relative to the derivative contract prices.

        At December 31, 2010, the fair value of the Partnership's forward foreign currency contracts was a net derivative instrument asset of $33.2 million. The net asset was due to the impact of a strengthening Canadian dollar relative to the US dollar on forward foreign exchange sales contracts used to hedge US dollar denominated cash flows. The weighted average fixed exchange rate for contracts outstanding at December, 2010 was $1.13 per US $1.00. Unrealized and realized gains and losses on foreign exchange derivatives are recorded in revenues.

        All non-financial derivative instruments are measured at fair value unless they are designated as contracts used for the purpose of receipt or delivery of a non-financial item in accordance with the Partnership's expected purchase, sale or usage requirements as defined by accounting standards, or are

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designated and qualify for hedge accounting. Some of the Partnership's natural gas purchase contracts that are used to meet power generation were not designated as contracts used in accordance with the Partnership's expected purchase requirements and therefore are recorded at fair value in the balance sheet.


Risk management and hedge accounting

        The Partnership uses various financial and non-financial derivatives primarily for risk management purposes. Unrealized changes in the fair value of financial and non-financial derivatives that either do not qualify for hedge accounting or the Partnership elects not to apply hedge accounting, and non-financial derivatives that do not qualify for the expected purchase, sale or usage requirements of the contract, are recorded in revenues or cost of fuel, as appropriate. The corresponding unrealized changes in the fair value of the associated economically hedged exposures are not recognized in income. Accordingly, derivative instruments that are recorded at fair value can produce volatility in net income as a result of fluctuating forward commodity prices, exchange rates and interest rates which are not offset by the unrealized fair value changes of the exposure being hedged on an economic basis. As a result, accounting gains or losses relating to changes in fair values of derivative instruments do not necessarily represent the underlying economics of the hedging transaction.

        For example, the Partnership records certain of its natural gas contracts at fair value because a small portion of this natural gas has been historically resold and not used in the production of electricity. Even though the economic impact from changes in natural gas prices is modest, for accounting purposes even a small change in natural gas prices can have a large impact on net income, other comprehensive income and equity. At December 31, 2010, holding all other variables unchanged, a $1/GJ increase (decrease) in the price of natural gas is estimated to increase (decrease) net income by $4 million and other comprehensive income by approximately $24 million.


Other comprehensive income

        Changes in the fair value of the effective hedge portion of the derivative contracts designated as accounting hedges, are recorded in other comprehensive income. The ineffective portion of the contracts is recorded in net income.

        For the year ended December 31, 2010, losses on derivative instruments designated as cash flow hedges, net of income taxes, of $44.5 million were recorded in other comprehensive income for the effective portion of cash flow hedges, while losses of $2.2 million for the ineffective portion of cash flow hedges were required to be recognized in net income. Of the $50.9 million in net unrealized fair value losses related to derivative instruments designated as cash flow hedges included in accumulated other comprehensive income at December 31, 2010, net losses of $3.2 million, net of taxes of $3.2 million are expected to settle and be reclassified to net income over the next twelve months.


BUSINESS RISKS

        The Partnership operates assets under long-term power and steam sales and energy supply contracts, which combined with an excellent ongoing maintenance program, minimize exposures to operational risk and commodity price and supply fluctuations. The most significant risks to the Partnership are those noted below.


Operational risk

        The operation of power plants involves many risks, including: (i) the breakdown or failure of, and the necessity to repair, upgrade or replace, power and steam generation equipment, transmission lines, pipelines or other equipment, structures or processes; (ii) the inability to secure critical or back-up parts for generator equipment on a timely basis; (iii) fire, explosion or other property damage; (iv) the

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inability to obtain adequate fuel supplies, site control and operation and maintenance and other site services; (v) performance of generation equipment below expected levels, including those pertaining to efficiency and availability; (vi) non-compliance with all operating permits and licences (including environmental permits and emissions restrictions) under applicable laws and regulations; and (vii) the inability to retain, at all times, adequate skilled personnel, the occurrence of any of which could have a material adverse effect on the Partnership.

        The failure of facilities to operate to certain capacity levels can result in the facilities having their contracted capacity reduced and in certain cases having to make payments on account of reduced capacity to power purchasers. Contract counterparties have remedies available to them on account of the Partnership's failure to operate facilities to contract requirements, including the recovery of damages or the termination of contractual arrangements.

        Under some of the plants' power purchase arrangements, if minimum amounts of power are not provided on a monthly basis, a reduction in payments from the power buyer will occur.

        Plant personnel have developed procedures to minimize the plant downtime required for both scheduled and unscheduled maintenance. The Partnership's maintenance practices are supported by an inventory of strategic spare parts, which can reduce downtime considerably in the event of failure. Safety standards are in place at all plants. In addition, the Partnership maintains reasonable insurance to cover losses resulting from equipment breakdown and business interruption, although there can be no assurance it will cover all losses.


PPA contract expiry risk

        Of the Partnership's fleet of power plants, 18 have power purchase arrangements in place that expire between April 2011 and 2027. In order to stabilize future cash flows, the Partnership will seek to re-contract its existing plants under new or extended contracts and acquire new plants that meet its investment criteria. The commercial environment for North American power generation is very competitive and therefore there is no assurance that the Partnership will be successful in re-contracting its existing plants or will be able to re-contract at existing or economic rates. Failure by the Partnership to enter into a subsequent power purchase arrangement on terms and at prices that permit the operation of a facility on a profitable basis could have a material adverse effect on the Partnership's operations and financial condition, and may even require the Partnership to temporarily or permanently cease operations at the affected facility.

        The PPAs for the North Carolina facilities expired on December 31, 2009. While the NCUC ruled on four fundamental issues in the arbitration process initiated by the Partnership, there is no assurance that new PPAs will be entered into between the Partnership and Progress or those new PPAs will result in positive annual cash provided by operating activities for the facilities (see Significant Events—Arbitration ruling for North Carolina plants and completion of enhancement project).

        The Navy has the right to terminate the SPAs for convenience on one year's notice. These agreements grant the Partnership access rights to the Naval Facilities that are operated to produce and sell electricity under the Naval Facility PPAs. The termination would result in the loss of the Naval Facilities' steam host and subsequently its QF status which in turn would allow SDG&E to terminate the Naval Facility PPAs. See "Business Risks—Qualifying Facility Status Risk". The Navy is obligated to pay a termination payment if it breaches an agreement or causes any loss of a Naval facility's QF status.

        The drop in power demand coupled with the high cost of capital and ongoing environmental regulatory uncertainty is expected to curtail the construction of new power generation facilities in North America. As demand returns, this should have a positive impact on PPA renewals that come due after the recessionary pressures have eased.

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Energy supply risk

        The Partnership requires energy in such forms as natural gas, wood waste, tire-derived fuel, coal, water and waste heat to generate electricity. A disruption in the supply of any energy supplies required by the Partnership could have a material adverse impact on the Partnership's business, financial condition and results of operation.

        Wood waste is required to fuel the Partnership's two Canadian biomass wood waste plants, Williams Lake and Calstock. In addition, the two North Carolina plants burn a mix of wood waste, tire-derived fuel and coal. Weakness in the North American economy has placed economic hardships on forestry mills, which has caused mills to shut down or scale back production in British Columbia, Ontario and in the US In the event that the Partnership's wood waste suppliers curtail or shut down operations, the Partnership's biomass wood waste operations could be adversely affected.

        Performance of hydroelectric facilities is dependent upon the availability of water. Variances in water flows, which may be caused by shifts in weather or climate patterns, the timing and rate of melting and other uncontrollable weather related factors affecting precipitation, or potential dam failure could result in volatility of hydroelectric plant revenues. There is an increasing level of regulation respecting the use, treatment, rate of flow and discharge of water, and respecting the licensing of water rights. A continued tightening of such regulations could have a material adverse effect on the Partnership's business, financial condition and results of operation.

        The Partnership's five Ontario plants (namely, Nipigon, Kapuskasing, North Bay, Calstock and Tunis) also generate electricity in part from the use of waste heat gases from adjoining natural gas compressor stations. Supply of the waste heat gases is secured under long-term contracts; however the availability of the waste heat gases varies depending on the output of the compressor stations along the TransCanada Canadian Mainline system, and the hosts altering those operations under the terms of a Waste Heat Optimization Agreement. In 2010, waste heat contributed to approximately 5% of power revenue at the Partnership's Ontario plants. Declining waste heat availability that began in 2007 continued through 2010 due to lower throughput on the TransCanada Canadian Mainline system and may remain lower than pre-2007 levels in the near term until throughput increases on the TransCanada Canadian Mainline system.


Commodity price risk

        The Partnership's power plant operations are susceptible to the risks associated with the uncertainty of the competitive marketplace in which the power plants operate, especially the volatility in market prices for electricity and fuel supply beyond any fixed price contract term.

        The price of fuel supplies is dependent upon a number of factors, including: the projected supply and demand for such fuel supplies; the quality of the fuel (particularly in regards to wood waste); and the cost of transporting such fuel supplies to the Partnership's facilities. Changes in any of these factors could increase the Partnership's cost of generating electricity or decrease the Partnership's revenues either of which could have a material adverse effect on the Partnership's business, financial condition and results of operation.

        Certain natural gas-fired facilities in the US have power purchase arrangements that extend beyond existing supply contracts. The failure to contract additional fuel supply at a cost that is equal to or better than existing contracted prices once existing contracts expire may lead to increased operating costs, disruptions in operations and reduced operating margins.

        Natural gas prices impact the ability of the Partnership to earn enhancement revenue and diversion sales from the curtailment of electricity production in favour of selling the unused natural gas at prevailing market prices.

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        Electricity prices under the PPAs for the Naval Facilities and the Oxnard facility are based on the purchasing utilities' SRAC. The SRAC formula is determined by the California Public Utility Commission (CPUC) and is subject to adjustment. In the future, the CPUC may make adjustments to the SRAC formula to change the basis on which future electricity prices will be determined for these facilities and such adjustments, which would affect the price of electricity and/or the price the Navy may have to pay for steam, may adversely affect the value of the affected PPAs to the Partnership.

        Certain of the Partnership's PPAs have fuel cost pass through mechanisms where revenues increase (decrease) as fuel costs increase (decrease). Because these costs are flowed through, they have minimal impact on net income or cash provided by operating activities. Other facilities dispatch (operation) is subject to the competitiveness of its fuel source versus other fuel sources in the region. This primarily affects the Manchief and North Carolina facilities as well as excess energy from the Morris facility. The impact of a change in natural gas prices on the overall dispatch of the Partnership's fleet as a whole is not expected to have a material impact on cash provided by operating activities or net income of the Partnership.


Environment, health and safety risk

        The Partnership's operations are subject to federal, provincial, state and local environmental, health and safety laws, regulations and guidelines. If the Partnership fails to comply with environmental, health and safety requirements, regulators could impose penalties and fines on the Partnership or curtail its operations. The Partnership's facilities could experience incidents, malfunctions or other unplanned events that could result in spills or emissions in excess of permitted levels and result in personal injury, penalties and property damage. As environmental laws, regulations and guidelines change, the Partnership may incur unforeseen capital expenditures and operating costs in order to comply, or may be unable to comply with more stringent standards causing the Partnership to close certain facilities.

        The Partnership has implemented environmental, health and safety management programs designed to continuously improve environmental, health and safety performance and is working towards alignment with the requirements of the ISO 14001 Environmental and the ISO 18000 Health and Safety Management Systems, a set of industry guidelines to achieve effective environmental, health and safety policies and procedures.

        As the Partnership's electricity generation business is an emitter of carbon dioxide (CO2), mercury and various local air contaminants, it must comply with emerging federal, state and provincial requirements including programs to offset emissions. As additional regulation is implemented, it is likely the Partnership will incur increased costs.

        Overall, the Partnership has a good fleet of power plants from an environmental perspective. The biomass facilities significantly reduce the release of CO2 that would otherwise occur with the decomposition of wood waste. The hydro facilities are not emitters. The Ontario natural gas-fired generation facilities utilize waste heat from adjacent natural gas compressor stations that reduce the use of natural gas. The combined heat and power facilities in the US maximize the use of energy by exporting steam to site hosts as a by-product of power generation.

        The Partnership has obtained all environmental licenses, permits, approvals and other authorizations required for the operation of the power plants. Except as outlined below, the Partnership is satisfied that its operating practices are in material compliance with applicable environmental laws and regulatory requirements. The power plants are operated in an environmentally sound manner and the environmental management systems are aligned with the corporate policies and procedures of CPC.

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Canadian Federal Government—Greenhouse Gas Emissions Regulations

        On June 23, 2010, the Canadian Environment Minister announced the Government of Canada's plan for new greenhouse gas (GHG) GHG emission regulation for coal-fired electricity generation units. The proposed plan will apply a new GHG emissions performance standard to new coal-fired electricity generation units and facilitate phasing out conventional coal-fired electricity generation in an orderly manner. The regulations are anticipated to be effective July 1, 2015 and units that have commercial operation dates prior to July 1, 2015 are expected to be exempt from the regulation until they reach the end of their economic useful life. Because the proposed regulations address coal-fired generation assets they are not expected to have any negative impact on the Partnership's facilities.

Canadian Federal Government—Air Emission Regulations

        The Canadian government is considering regulations which may place stricter limits on nitrogen oxide (NOx), sulphur dioxide (SO2), mercury and particulate matter emissions from fossil fuel-fired generating stations in Canada. The Canadian Department of Environment has been working with the provincial governments and industry to develop a regulatory framework to minimize local emissions under a Comprehensive Air Management System (CAMS) and the regulations are expected to be implemented in 2013. There is insufficient information to assess the financial implication to the Partnership's operations, although as additional regulation is passed it is likely the Partnership will incur increased costs.

Ontario

        The Ontario government aims to harmonize its cap and trade program with the Western Climate Initiative (WCI), which is represented by four provinces (B.C., Ontario, Quebec and Manitoba) and eleven states. The WCI requires a 15% reduction in GHG emission levels by 2020, from those of 2005. The cap and trade system applicable to industrial facilities including electricity generation is expected to be implemented in 2012. However, the Ontario Government has not yet provided the industry specific GHG reduction targets or other program details. Accordingly, there is insufficient information to determine the impact of this proposed system on the Partnership, although as additional regulation is passed it is likely that the Partnership will incur increased costs.

British Columbia

        The Greenhouse Gas Reduction Targets Act and the Greenhouse Gas Reduction (Cap and Trade) Cap and Trade Act which were enacted in 2008, provide the statutory basis for establishing a market-based framework to reduce GHG emissions from large emitters. The BC Government aims to harmonize its cap and trade program with the WCI, similar to Ontario. The cap and trade system applicable to industrial facilities including electricity generation is expected to start in 2012 and will replace the current fuel tax. However, the BC Government has not yet provided the industry specific GHG reduction targets or other program details. Accordingly, there is insufficient information at this time to determine the impact of this proposed system on the Partnership, although as additional regulation is passed it is likely that the Partnership will incur increased costs.

US—Greenhouse Gas Regulation

        The US Environmental Protection Agency (USEPA) and the state of California have implemented mandatory GHG reporting requirements, which are expected to be met by the Partnership on their respective due dates in 2011. The USEPA is expected to regulate GHGs under the Clean Air Act (CAA) with requirements for best available control technology for new GHG sources and major modifications of existing sources. They also plan to control GHG emissions for existing and new sources through new source performance standards. The WCI, as described above under Ontario, may

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affect the operation of the Partnership's four facilities in California and the Frederickson facility in Washington.

        California's proposed Cap and Trade program to control GHGs aims to cut the state's GHG emissions to 1990 levels by 2020 with further reductions each year thereafter. The initial phase of the program will apply to electric generation and large industrial units and is expected to be effective in January 2012, but the proposal's GHG emission allocation methodology has not yet been established. On November 2, 2010, a proposition (Proposition 23) to effectively repeal the program was rejected by California voters.

        There is currently insufficient information to determine the impact of the proposed regulations on the Partnership, however if additional regulations are passed it is likely that the Partnership will incur increased costs.

US—Air Emission Regulations

        In July, 2010, USEPA proposed the Clean Air Transport Rule (CATR) to replace the Clean Air Interstate Rule. CATR proposes to reduce the amount of NOx and SO2 emissions from electric generating units that are transported in the air to down-wind states. CATR proposes emission reductions sufficient to contribute to reducing NOx and SO2 measures below the ambient air quality standards in those down-wind states. The CATR proposals are also expected to significantly limit emissions trading.

        CATR only applies to units of generating facilities with a capacity of 25 MW or more, although it may be extended to other facilities when it is re-evaluated in 2014. Cogeneration facilities and units not providing electricity for sale on the electricity grid are also exempt. The Partnership units that may be impacted are Roxboro, Southport, and Morris, however, there is insufficient information to understand the implications of the proposed regulations.

        There is currently insufficient information to determine the impact of these air emission proposed regulations on the Partnership, however if additional regulations are passed it is likely that the Partnership will incur increased costs.

        In 2010, the USEPA proposed new air toxics standards, including standards for mercury, for industrial boilers (Boiler MACT) and for coal and oil-fired electric generating units. However, the state of North Carolina issued a maximum available control technology permit to the Partnership under the CAA, which precludes the application of these proposed new standards to its North Carolina facilities. In addition, based on the fuel mix and newly installed controls at the Partnership's North Carolina facilities, the Partnership does not anticipate the need for further mercury or other hazardous emissions controls at these facilities.

US—Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

        CERCLA, also referred to as Superfund, requires investigation and remediation of sites where there has been a release or threatened release of hazardous substances. It also authorizes the USEPA to take response actions at Superfund sites, including ordering parties who are potentially responsible for the release to pay for their actions. Many states have similar laws. CERCLA defines potentially responsible broadly to include past and present owners and operators, as well as generators, of wastes sent to a site. The Partnership is currently not subject to any material liability for any Superfund matters. However, the Partnership generates certain wastes, including hazardous wastes, and sends certain of its wastes to third party waste disposal sites. As a result, there can be no assurance that the Partnership will not incur a liability under CERCLA in the future.

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Acquisition and development risk

        The ability of the Partnership to sustain current cash flow is subject to the Partnership finding cash accretive investments to replace potential future declines in cash flow as contracts expire and may not be replaced under similar terms. The acquisition of power generation companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets and the inability to arrange financing for an acquisition as may be required or desired. Despite extensive due diligence procedures prior to any acquisition, there can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them.

        Development of power generation facilities is subject to substantial risks, including various engineering, construction, stakeholder, government and environmental risks. Generally, in developing a power generation facility, there are numerous tasks the Partnership must complete, including: government permits and approvals; site agreements and construction contracts; access to power grids and electrical transmission agreements; fuel supply and transportation agreements; equipment; and financing. There can be no assurance that the Partnership will be successful in completing such tasks on a timely basis or at all. The development and future operation of power generation facilities can be adversely affected by changes in government policy and regulation, environmental concerns, increases in capital costs, increases in interest rates, competition in the industry, labour availability, labour disputes, increases in material costs and other matters beyond the direct control of the Partnership.

        In the event that a project is not completed or does not operate at anticipated performance levels, the Partnership may not be able to recover its investment, materially and adversely affecting the Partnership's financial position, operating results and business.

        The Partnership attempts to mitigate these risks by performing detailed project analyses and due diligence prior to and during construction or acquisition. Corrective actions are taken when necessary to increase the likelihood of investment recovery. The Partnership also seeks to enter into favourable long-term contracts for the projects' output whenever possible.


Government and political risk

        The Partnership is subject to risks associated with changes in federal, provincial, state or local laws, regulations and permitting requirements. It is not possible to predict changes in laws or regulations that could impact the Partnership's operations, income tax status or ability to renew permits, as required. The introduction of price caps or, in the case of Ontario, the continuation of price caps, may suppress price increases under the Partnership's PPAs. The upcoming leadership races and provincial elections in British Columbia and Ontario may result in changes in energy or environmental policy that could impact the Partnerships operations.


Foreign exchange risk

        The Partnership owns and operates power facilities in the US, has borrowings outstanding that are denominated in US dollars and has net cash flow that is generated in US dollars. Therefore, fluctuations in the exchange rate between the US dollar and the Canadian dollar could impact the Partnership's income and cash flows and have an adverse effect on financial performance and condition.

        The Partnership manages the foreign exchange risk of its future anticipated US dollar-denominated cash flows from its US plants net of debt service obligations on US dollar borrowings through the use of foreign exchange contracts for periods up to seven years. At December 31, 2010, US$308.9 million had been economically hedged for 2011 to 2016 at a weighted average exchange rate of 1.13 per US $1.00.

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        By year, the amounts hedged and average rates are as follows:

 
  2011   2012   2013   2014   2015   2016  

Forward foreign exchange sales (milions of US dollars)

    57.7     56.0     54.7     54.8     44.8     40.9  

Average exchange rate (US / CDN)

    1.15     1.13     1.18     1.10     1.17     1.05  


Qualifying facility status risk

        Similar to being dependent on counterparties for steam sales, certain US facilities are also dependent on their QF status. The loss of QF status could have adverse consequences to the Partnership and the facility could become subject to rate regulation by FERC under the US Federal Power Act and additional state regulation. Loss of QF status could also trigger defaults under covenants to maintain QF status in the facilities' PPAs, SPAs and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. Loss of QF status on a retroactive basis could lead to, among other things, fines and penalties or claims by a utility customer for a refund of payments previously made and the Partnership cannot provide assurance that the costs incurred in connection with the facility could be recovered through sales to other purchasers. If a steam host facility were to become insolvent, it could result in the loss of QF status if operations cease.


Conflict of interest risk related to the Partnership's relationship with CPC

        As a result of CPC's relationship with the Partnership, certain conflicts of interest could arise from time to time in which the Partnership's interests are not aligned with those of CPC. For example, the strategic review may result in a situation in which the same potential alternatives do not serve the best interests of both parties equally.

        The Partnership's terms of reference for the board of directors of the General Partner denotes that the board of directors shall be composed of not more than eight members, at least four of whom shall be independent directors who are not officers, directors or employees of CPC or its affiliates and are free from any direct or indirect interest, any business or other relationship that could interfere with a director's independence or ability to act in the best interests of the General Partner and the Partnership. There are four senior officers of CPC who are members of the General Partner's board of directors and are not considered independent. The Chairman, who is an executive officer of CPC, has a casting vote in case of a tie vote at any meeting of the board of directors. Any non-arms' length agreements are evaluated and monitored solely by a committee of independent directors of the Partnership. Further a committee of the independent directors, referred to as the Special Committee, was established to review and consider on behalf of the Partnership potential alternatives for the restructuring of the relationship between CPC and the Partnership.


Tax risk

        On December 15, 2008, the fifth protocol to the US-Canada Income Tax Treaty (Treaty) entered into force. The protocol contains extensive changes to the current Treaty. Although the Treaty contains positive changes such as the elimination of non-resident withholding tax on interest, it also included the addition of a treaty denial provision applicable to payments obtained from or through certain hybrid entities. The treaty denial provision was effective January 1, 2010. While the Partnership does not expect to be immediately impacted by the treaty denial provision, the provision could negatively impact the Partnership's ability to repatriate future profits arising from US operations to Canada.

        Over the last several years, numerous proposals have been made to tighten the US rules (Earnings Stripping Rules) with respect to the deductibility of interest paid by US corporations to, or guaranteed by related parties, who do not fully pay US tax on such interest income. On November 28, 2007, the US Treasury Department issued a report on three international tax issues including the Earnings

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Stripping Rules that concluded that broad based tightening of the Earnings Stripping Rules was warranted. On February 1, 2010, the President of the US transmitted the 2011 Budget to the Congress. The Budget includes measures proposing to tighten for certain entities only the Earnings Stripping Rules effective for tax periods beginning after December 31, 2010. The measures need passage by both houses of Congress before they are enacted but assuming they are substantively enacted as proposed, the measures are not expected to apply to the Partnership or its subsidiaries.

        The Partnership's operations are complex and the computation of the provision for income taxes involves tax interpretations, regulations, and legislation that are continually changing. In addition, the Partnership's tax filings are subject to audit by taxation authorities. While the Partnership believes that its tax filings have been made in accordance with all such tax interpretations, regulations, and legislation, the Partnership cannot guarantee that it will not have disagreements with the Canada Revenue Agency or other taxation authorities with respect to the Partnership's tax filings. Future changes in tax legislation, not limited to changes or potential changes discussed above may have an adverse impact on the Partnership, its Unitholders and the value of the Units.

        The Partnership monitors the development of any potential changes in tax legislation in order to manage the risks by proactively planning for any changes.


Counterparty credit risk

        Counterparty credit risk is the possible financial loss associated with the potential inability of counterparties to satisfy their contractual obligations to the Partnership, including payment and performance. In the event of default by a purchasing counterparty, existing PPAs and SPAs may not be replaceable on similar terms, particularly those agreements that have favourable pricing for the Partnership relative to their current markets. The Partnership is also dependant upon counterparties with respect to its cogeneration hosts and suppliers of fuel to its plants. Failure of any such counterparties could impact the operations of some of the Partnership's plants and could adversely impact the Partnership's financial results. In the wholesale electricity market, should a counterparty default, the Partnership may not be able to effectively replace such counterparty in order to manage short or long electricity positions, resulting in reduced revenues or increased power costs. Furthermore, a prolonged deterioration in economic conditions, such as the recent economic recession, could increase the foregoing risks and could have a material adverse affect on the Partnership.

        Counterparty credit risk is managed by making appropriate credit assessments of counterparties on an ongoing basis, dealing with creditworthy counterparties, diversifying the risk by using several counterparties and where appropriate and contractually allowed, requiring the counterparty to provide appropriate security.


Weather and catastrophic event risk

        Weather conditions and other unforeseen natural events could force the Partnership's facilities to cease operations which could adversely affect the Partnership.

        A natural disaster or other catastrophic event, such as an earthquake, hurricane, fire, explosion, flood, severe storm, terrorist attack or other comparable event at any of the Partnership's facilities, or to supplying pipelines or transmission lines could disrupt operations at or cause substantial damage to such facilities. While the Partnership has obtained insurance, including earthquake insurance, to mitigate financial costs arising from such events, there is no assurance that such insurance will fully cover such risks and costs or will continue to be available to the Partnership on terms which are commercially reasonable.

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Risks associated with strategic review

        The outcome of the strategic review of alternatives may not meet market expectations and may impact the value of the Partnership units.


General economic conditions and business environment

        In addition to all of the risks previously enumerated the Partnership is subject to adverse changes in its markets and general economic conditions. The Partnership is exposed to risks associated with the development and retention of a qualified workforce, technology, fluctuations in foreign exchange or interest rates, market competition, lawsuits, risks that are not fully covered by our various insurance policies, risks of a pandemic or the risk that the Partnership is unable to comply with the changes to the new IFRS reporting requirements on a timely basis. These risks could have an adverse impact on the Partnership's business, prospects, financial condition, results of operation or cash flows.


Preferred Share guarantee—unit distribution risk

        The Series 1 Shares, Series 2 Shares and Series 3 Shares are fully and unconditionally guaranteed by the Partnership on a subordinated basis as to (i) payment of dividends, as and when declared, (ii) payment of amounts due on redemption of the Series 1 Shares, Series 2 Shares and Series 3 Shares, and (iii) payment of amounts due on liquidation, dissolution or winding up of CPI Preferred Equity Ltd. (CPEL).

        As long as the declaration or payment of dividends on the Series 1 Shares, Series 2 Shares or Series 3 Shares is in arrears, the Partnership will not make any distributions on the Units. The market value of the Units may decline if the Partnership is unable to meet its cash distribution targets in the future, and that decline may be significant.


Structural subordination risk

        The right of the Partnership, as a shareholder of any of its subsidiaries, to realize on the assets of a subsidiary in the event of the bankruptcy or insolvency of the subsidiary would be subordinate to the rights of unsubordinated creditors of such subsidiary, holders of unsubordinated preferred shares of such subsidiary, including the Series 1 Shares, Series 2 Shares and Series 3 Shares of CPEL, and claimants preferred by statute.


Limited liability risk

        A unitholder may lose the protection of limited liability if it takes part in the management or control of the business of the Partnership or does not comply with applicable legislation governing limited partnerships.

        There is no assurance that risk management steps taken will avoid future loss due to the occurrence of the above described or unforeseen risks.


OUTLOOK

        Changes in the Partnership's outlook that may result from the review of its strategic alternatives will depend on the outcome of this process. The process to review strategic alternatives is ongoing and the Partnership anticipates it will be able to provide an update in the second quarter of 2011. During the process to review the strategic alternatives it is anticipated that the Partnership will continue to provide the same amount of monthly distributions to its unitholders, maintain the same investor proposition supported by its high quality portfolio of contracted power assets and continue to deliver on business plan priorities.

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        The long-term outlook for the Partnership has not changed substantially from prior reporting periods. Our assets and contracts are expected to provide long-term stable cash flows. While the Partnership is now subject to Canadian SIFT taxes, the Partnership does not expect to make any material cash income tax payments until 2015 or 2016 in both Canada and the US, due to tax attributes consisting primarily of tax losses and undepreciated capital cost pools available to the Partnership to deduct against future taxable income.

        The Partnership expects cash provided by operating activities before working capital changes in 2011 will be higher than in 2010 as the Partnership benefits from the reinvestment in its plants, such as the Oxnard turbine replacement and North Carolina enhancement projects. The anticipated increase in cash provided by operating activities is primarily the result of expected higher dispatch and better terms in new PPAs at the North Carolina plants and higher contracted prices on foreign exchange contracts that will settle in 2011 versus 2010. Partially offsetting these increases is an anticipated increase in natural gas transportation cost at the Ontario plants of $4 million in 2011 compared to 2010 as a result of higher tolls on the TransCanada Canadian Mainline. The Partnership continues to face uncertainty in respect of the timing of finalization and terms of new PPAs for the North Carolina facilities.

        The Partnership continues to expect that current annual distributions of $1.76 per unit can be maintained until the end of 2014, based on its current strategy which may change depending on the outcome of the Partnership's review of its strategic alternatives. The ability of the Partnership to sustain cash flows to 2014 and beyond is subject to a number of risks and uncertainties including:

        The Partnership expects maintenance capital expenditures in 2011 to be $7 million to $9 million higher than in 2010. Maintenance capital expenditures in 2010 of $17 million were below the Partnerships long-term expectations of $20 million to $22 million.

        The PPAs for the North Carolina facilities expired on December 31, 2009. The Partnership initiated an arbitration process with the NCUC seeking long-term PPAs with pricing terms consistent with Progress's actual avoided costs. The NCUC issued a decision in January 2011 setting out guidelines for the new PPAs (see Significant Events—Arbitration ruling for North Carolina plants and completion of enhancement project). The Partnership is negotiating terms of the new PPA with Progress. While the NCUC ruling supported the majority of the Partnership's positions, it did not completely align with the Partnership's economic projections. Accretion for the enhancement project at the North Carolina facilities will be significantly lower than the $0.10 per unit previously disclosed. The Partnership will specifically quantify and disclose the project's financial expectations once PPA terms have been finalized, which is expected to be in the second quarter.

        In the fourth quarter of 2010, the Partnership completed the final phase of the enhancement project on the North Carolina facilities designed to reduce environmental emissions and improve economic performance by increasing the use of tire-derived fuel and wood waste in the fuel mix. Project costs incurred to December 31, 2010 were US$82 million with an additional US$5 million to be spent in 2011 on access roads and final testing. The Partnership had anticipated a reduction in the capacity of Southport and Roxboro to approximately 88 megawatts (MW) and 46 MW respectively as a result of the increased use of wood waste and tire-derived fuel. The reduction in the capacity levels as

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a result of the change to a greater level of wood waste and tire-derived fuel in the fuel mix may be greater than previously expected. Recent testing indicates the plants may only be able to achieve capacities of 84-87 MW at Southport and 42-44 MW at Roxboro based on the targeted fuel mix. Management is assessing whether a shortfall in capacity can be practically resolved.

        The Partnership has the option to extend the Nipigon PPA for an additional 10 years beyond the end of the current term in 2012 with the same financial terms, which removes the near-term recontracting risk at this facility.

        The Morris facility has participated in capacity auctions in the PJM market for the 100 MW of its capacity that exceeds Equistar's requirements. The capacity is currently sold to Exelon Generation Company, LLC under a contract that expires in April 2011. Capacity has been sold from May 2011 to April 2014. Auction prices are lower than the Exelon contract and as a result capacity revenue will be approximately $2 million lower in 2011 and $4 million to $5 million lower in 2012 and 2013 compared to 2010.

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QUARTERLY INFORMATION
Selected Quarterly and Annual Consolidated Financial Data

 
  2010  
Three months ended
  Mar. 31   Jun. 30   Sep. 30   Dec. 31   Total  
(millions of dollars except unit and per unit amounts)
   
   
   
   
   
 

Revenues

                               
 

Ontario plants

    44.2     30.1     29.3     39.6     143.2  
 

Williams Lake

    11.1     11.3     11.9     7.9     42.2  
 

BC hydroelectric plants

    4.1     6.4     4.7     4.6     19.8  
 

Northwest US plants

    14.9     14.3     14.8     13.7     57.7  
 

California plants

    23.6     23.3     31.8     33.9     112.6  
 

Curtis Palmer

    10.5     7.9     5.8     12.7     36.9  
 

Northeast US natural gas plants

    21.4     14.8     20.5     16.1     72.8  
 

North Carolina plants

    8.1     7.6     10.3     10.2     36.2  
 

PERC management

    0.9     0.8     0.8     0.7     3.2  
 

Fair value changes on foreign exchange contracts

    5.4     (19.2 )   10.8     10.8     7.8  
                       

    144.2     97.3     140.7     150.2     532.4  
                       

Operating Margin(1)

                               
 

Ontario plants

    19.3     6.6     5.4     14.7     46.0  
 

Williams Lake

    7.1     5.6     8.1     3.5     24.3  
 

BC hydroelectric plants

    3.0     5.3     3.0     3.5     14.8  
 

Northwest US plants

    9.5     8.4     8.6     7.7     34.2  
 

California plants

    3.2     9.2     14.9     1.1     28.4  
 

Curtis Palmer

    9.1     6.6     4.4     11.4     31.5  
 

Northeast US natural gas plants

    4.1     3.9     6.4     3.0     17.4  
 

North Carolina plants

    (1.9 )   (1.7 )   (0.5 )   (3.2 )   (7.3 )
 

PERC management fees

    0.7     0.4     0.5     0.2     1.8  
 

Fair value changes on foreign exchange contracts

    5.4     (19.2 )   10.8     10.8     7.8  
 

Fair value changes on natural gas supply contracts

    (8.6 )   1.4     (4.9 )   0.7     (11.4 )
                       

    50.9     26.5     56.7     53.4     187.5  

Other costs

                               
 

Depreciation, amortization and accretion

    23.5     26.3     25.1     23.4     98.3  
 

Financial charges and other, net

    11.0     8.0     10.6     10.5     40.1  
 

Management and administration

    4.0     1.6     5.3     3.0     13.9  
                       

    38.5     35.9     41.0     36.9     152.3  

Net income (loss) from continuing operations before income tax and preferred share dividends

    12.4     (9.4 )   15.7     16.5     35.2  

Income tax expense (recovery)

    (5.5 )   (4.0 )   1.7     (1.6 )   (9.4 )

Preferred share dividends of a subsidiary company

    3.6     3.6     3.4     3.5     14.1  
                       

Net income (loss) from continuing operations

    14.3     (9.0 )   10.6     14.6     30.5  
                       
 

Per unit

  $ 0.26   $ (0.16 ) $ 0.19   $ 0.26   $ 0.55  
                       

Cash provided by operating activities of continuing operations

    37.5     7.4     35.3     37.6     117.8  
 

Per unit(1)

  $ 0.82   $ 0.14   $ 0.64   $ 0.68   $ 2.14  

Distributions

    23.9     24.2     24.3     24.5     96.9  
 

Per unit

  $ 0.44   $ 0.44   $ 0.44   $ 0.44   $ 1.76  

Capital Expenditures

    4.6     8.2     8.7     6.8     28.3  

Weighted Average Units Outstanding (millions)

    54.3     54.7     55.2     55.6     55.0  

(1)
The selected quarterly and annual consolidated financial data has been prepared in accordance with Canadian generally accepted accounting principles except for operating margin and cash provided by operating activities per unit. See Non-GAAP Measures.

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QUARTERLY INFORMATION
Selected Quarterly and Annual Consolidated Financial Data

 
  2009  
Three months ended
  Mar. 31   Jun. 30   Sep. 30   Dec. 31   Total  
(millions of dollars except unit and per unit amounts)
   
   
 

Revenues

                               
 

Ontario plants

    43.7     32.5     29.0     40.2     145.4  
 

Williams Lake

    11.0     10.1     10.8     11.0     42.9  
 

BC hydroelectric plants

    2.5     5.5     2.9     4.8     15.7  
 

Northwest US plants

    15.7     16.4     15.6     15.4     63.1  
 

California plants

    21.8     24.7     29.4     21.1     97.0  
 

Curtis Palmer

    10.2     13.0     6.9     12.0     42.1  
 

Northeast US natural gas plants(2)

    27.5     21.4     21.0     20.7     90.6  
 

North Carolina plants

    10.5     6.7     6.2     3.9     27.3  
 

PERC management fees

    0.9     1.0     1.0     0.7     3.6  
 

Fair value changes on foreign exchange contracts

    (16.2 )   33.9     32.7     8.4     58.8  
                       

    127.6     165.2     155.5     138.2     586.5  
                       

Operating Margin(1)

                               
 

Ontario plants

    19.8     9.7     7.2     16.0     52.7  
 

Williams Lake

    6.9     5.8     8.4     6.7     27.8  
 

BC hydroelectric plants

    1.5     4.4     1.6     3.6     11.1  
 

Northwest US plants

    8.9     9.3     9.0     9.5     36.7  
 

California plants

    1.5     9.5     15.8     3.0     29.8  
 

Curtis Palmer

    8.7     11.6     5.4     10.6     36.3  
 

Northeast US natural gas plants(2)

    3.9     4.7     6.3     3.5     18.4  
 

North Carolina plants

    (2.3 )   (3.2 )   (0.9 )   (3.6 )   (10.0 )
 

PERC management

    0.6     0.7     0.6     0.6     2.5  
 

Fair value changes on foreign exchange contracts

    (16.2 )   33.9     32.7     8.4     58.8  
 

Fair value changes on natural gas supply contracts

    (34.1 )   1.3     (20.2 )   0.6     (52.4 )
                       

    (0.8 )   87.7     65.9     58.9     211.7  

Other costs

                               
 

Depreciation, amortization and accretion

    23.8     23.3     22.9     23.3     93.3  
 

Financial charges and other, net

    13.1     11.2     11.1     11.0     46.4  
 

Management and administration

    4.3     2.9     3.7     4.3     15.2  
                       

    41.2     37.4     37.7     38.6     154.9  

Net income (loss) from continuing operations before income tax and preferred share dividends

    (42.0 )   50.3     28.2     20.3     56.8  

Income tax expense (recovery)

    (11.0 )   6.3     (4.2 )       (8.9 )

Preferred share dividends of a subsidiary company

    1.6     1.7     1.7     2.9     7.9  
                       

Net income (loss) from continuing operations

    (32.6 )   42.3     30.7     17.4     57.8  
                       
 

Per unit

  $ (0.60 ) $ 0.78   $ 0.57   $ 0.32   $ 1.07  
                       

Cash provided by operating activities of continuing operations(3)

    33.7     33.1     33.8     33.9     134.5  
 

Per unit(1)

  $ 0.63   $ 0.61   $ 0.63   $ 0.63   $ 2.50  

Distributions

    34.0     23.7     23.7     23.8     105.2  
 

Per unit

  $ 0.63   $ 0.44   $ 0.44   $ 0.44   $ 1.95  

Capital Expenditures(3)

    17.0     25.9     33.0     24.8     100.7  

Weighted Average Units Outstanding (millions)

    53.9     53.9     53.9     54.0     53.9  
                       

(1)
The selected quarterly and annual consolidated financial data has been prepared in accordance with Canadian generally accepted accounting principles except for operating margin and cash provided by operating activities per unit. See Non-GAAP Measures.

(2)
Restated to reflect the operations of Castleton as discontinued operations. Castleton sold in May 2009.

(3)
The Partnership made an immaterial adjustment to the 2009 financial statements to reflect the reclassification of $5.2 million of property, plant and equipment to inventory resulting in a decrease in cash provided by operating activities and capital expenditures in the fourth quarter. There was no impact to net earnings resulting from this adjustment.

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Operating Margin(1) and Plant Output

 
  Three months ended
December 31
  Year ended December 31  
(millions of dollars except GWh)
  GWh   2010   GWh   2009   GWh   2010   GWh   2009  

Ontario plants

    365     14.7     352     16.0     1,276     46.0     1,330     52.7  

Williams Lake

    144     3.5     146     6.7     560     24.3     362     27.8  

BC hydroelectric plants

    66     3.5     70     3.6     306     14.8     232     11.1  

Northwest US plants

    133     7.7     293     9.5     741     34.2     990     36.7  

California plants

    237     1.1     274     3.0     935     28.4     971     29.8  

Curtis Palmer

    120     11.4     108     10.6     333     31.5     356     36.3  

Northeast US natural gas plants(2)

    157     3.0     158     3.5     604     17.4     657     18.4  

North Carolina plants

    88     (3.2 )   4     (3.6 )   258     (7.3 )   65     (10.0 )

PERC management

        0.2         0.6         1.8         2.5  

Fair value changes

        11.5         9.0         (3.6 )       6.4  
                                   

    1,310     53.4     1,405     58.9     5,013     187.5     4,963     211.7  
                                   

 

 
  Three months
ended
December 31
  Year ended
December 31
 
Weighted Average Plant Availability(1)
  2010   2009   2010   2009  

Ontario plants

    99 %   96 %   95 %   93 %

Williams Lake

    98 %   100 %   96 %   98 %

BC hydroelectric plants

    98 %   87 %   91 %   86 %

Northwest US plants

    97 %   96 %   94 %   97 %

California plants

    94 %   99 %   91 %   93 %

Curtis Palmer

    100 %   100 %   100 %   94 %

Northeast US natural gas plants(2)

    99 %   99 %   98 %   99 %

North Carolina plants

    93 %   56 %   93 %   69 %
                   

Weighted Average Total

    97 %   92 %   95 %   92 %
                   

(1)
Operating margin is a non-GAAP financial measure. See Non-GAAP Measures.

(2)
Plant availability represents the percentage of time in the period that the plant is available to generate power, whether actually running or not, and is reduced by planned and unplanned outages.

(3)
Restated to reflect the operations of Castleton as discontinued operations. Castleton was sold in May 2009.


Factors impacting quarterly financial results

        The Partnership's Selected Quarterly Financial Data, which has been prepared in accordance with GAAP, except as noted, is set out above. Quarterly revenues, net income and cash provided by operating activities are affected by seasonal contract pricing, seasonal weather conditions, fluctuations in US dollar exchange rates relative to the Canadian dollar, attainment of firm energy requirements, natural gas prices, waste heat availability and planned and unplanned plant outages, as well as items outside of the normal course of operations. Quarterly net income is also affected by fair value changes in foreign exchange contracts and natural gas supply contracts.

        The Partnership's cash flow tends to be relatively stable over the year with seasonal fluctuations at the individual facilities. Under the power sales contracts for the Ontario plants, the Partnership receives

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higher per MWh prices in the winter months (October to March) and lower prices in the summer months (April to September). The lower summer prices reduce the threshold for economic curtailments thereby increasing the profitability of enhancements, natural gas prices being equal. Contributions from Williams Lake are usually lower in the fourth quarter once the annual firm energy requirements are fulfilled and the plant is only producing lower-priced excess energy. The Naval facilities earn approximately 75% of their capacity revenue during the summer peak demand months and all the California plants can earn performance bonuses during these months. Revenues from the hydroelectric facilities are generally higher in the spring months due to seasonally higher water flows.

        Significant items which impacted the last eight quarters' net income were as follows:

        The Partnership recorded gains on the change in the fair value of the natural gas supply contracts in the second and fourth quarters of 2009 and the second quarter of 2010. Losses were recorded in the first and third quarters of 2009 and the first, third and fourth quarters of 2010.

        Unrealized fair value changes on foreign exchange contracts resulted in gains in the second, third and fourth quarters of 2009 and the first, third and fourth quarters of 2010. Losses were recorded in the first quarter of 2009 and the second quarter of 2010.


Factors impacting the fourth quarter financial results

        The Partnership reported cash provided by operating activities of continuing operations of $37.6 million or $0.68 per unit for the three months ended December 31, 2010 compared to $33.9 million or $0.63 per unit for the same period in 2009. Cash provided by operating activities per unit is defined previously under Non-GAAP Measures. The $3.7 million increase in cash provided by operating activities of continuing operations for the three months ended December 31, 2010 compared to the same period in 2009 is primarily due to the following:

        Increases were partially offset by the following:

        Revenue for the three month period ended December 31, 2010 was $150.2 million compared to $138.2 for the same period in 2009. The increase was primarily due to higher revenues at the North Carolina plants as a result of higher dispatch and higher revenues at Oxnard in 2010 compared to 2009 as the completion of the turbine upgrade was considered to be sold to SCE in exchange for a long-term receivable in 2010.

        The Partnership reported net income from continuing operations of $14.6 million or $0.26 per unit for the three months ended December 31, 2010 compared to $17.4 million or $0.32 per unit for the same period in 2009. Net income from continuing operations decreased by $2.8 million primarily due to lower operating margins at Williams Lake and Manchief.

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FORWARD-LOOKING INFORMATION

        Certain information in this MD&A is forward-looking and related to anticipated financial performance, events and strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target" and "expect" or similar words suggest future outcomes. By their nature, such statements are subject to significant risks, assumptions and uncertainties, which could cause the Partnership's actual results and experience to be materially different than the anticipated results. In particular, forward-looking information and statements include: (i) the sustainability of distributions, (ii) planned capital expenditures at Southport in 2011 and the anticipated total cost of the Southport and Roxboro enhancement project, including capacity levels, (iii) anticipated completion of the Southport facility modifications and the impact of the Southport and Roxboro facility modifications on the operation and economic performance of the facilities and their emissions (iv) expectations regarding the Partnership's cash provided by operating activities, capital expenditures and working capital in 2011 and distributions relative to net income in 2011, (v) expectations regarding the time at which the Partnership make material cash income tax payments, (vi) expectations on the throughput on the TransCanada Canadian Mainline and related expectations regarding waste heat availability at the Ontario facilities, (vii) expectations regarding the financing of the Partnership's capital expenditures, (viii) expectations with respect to maintaining the current distribution levels until the end of 2014, (ix) expectations in respect of new PPAs at the North Carolina facilities, including timing for their being finalized, and expectations with respect to the Partnership's long-term outlook for the North Carolina plants, including in respect of accretion from the enhancement project at the North Carolina plants, (x) expected maintenance capital spending of $24 million to $26 million in 2011 and expectations that over a five year planning cycle maintenance capital expenditures will average $20 million to $22 million annually for the Partnership's existing facilities, (xi) expectations regarding the introduction of new emissions regulation and the costs to comply with, and other impacts of, current and anticipated emissions regulation, (xii) the expected impact of transition to IFRS including with respect of specific balances identified under Future Accounting Standards—International Financial Reporting Standards, (xiii) expectations of the timing of the process to review strategic alternatives and expectations that the Partnership will seek growth opportunities that fit the Partnership's strategy and deliver on business plan priorities, (xiv) the monthly distributions of the Partnership while the strategic review process is underway, (xv) expectations for capacity revenues at the Morris facility in 2011, 2012 and 2013, (xvi) expected future payment obligations under various agreements and in respect of asset retirement obligations, and (xvii) expected changes in the transportation costs on the TransCanada Canadian Mainline.

        These statements are based on certain assumptions and analysis made by the Partnership in light of its experience and perception of historical trends, current conditions and expected future developments and other factors it believes are appropriate. The material factors and assumptions used to develop these forward-looking statements include, but are not limited to: (i) the Partnership's operations, financial position, available credit facilities and access to capital markets, (ii) the Partnership's assessment of commodity, currency and power markets, (iii) the markets and regulatory environment in which the Partnership's facilities operate, (iv) the state of capital markets, (v) management's analysis of applicable tax legislation, (vi) the assumption that the currently applicable and proposed tax laws will not change and will be implemented, (vii) the assumption that counterparties to fuel supply, power purchase and other agreements will continue to perform their obligations under the agreements taking account of the matters described herein, (viii) that current expectations regarding throughput on the TransCanada Canadian Mainline will continue, (ix) the level of plant availability and dispatch, (x) the performance of contractors and suppliers, (xi) the renewal or replacement and terms of PPAs including the terms and timing of new PPAs at the North Carolina facilities, (xii) the ability of the Partnership to successfully realize the benefits of its capital projects, (xiii) the ability of the Partnership to implement its strategic initiatives and whether such initiatives will yield the expected benefits, (xiv) expected water flows, (xv) the ability of the Partnership to adequately

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source alterative sources of supply of wood waste, (xvi) currently applicable and proposed environmental regulation will be implemented, (xvii) the ability to manage the transition to IFRS, (xviii) the Partnership's assessment of the strategic alternatives that may be available to it, and (xix) factors and assumptions noted under Outlook in respect of the forward looking statements and information noted in that section.

        Whether actual results, performance or achievements will conform to the Partnership's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from the Partnership's expectations. Such risks and uncertainties include, but are not limited to risks relating to (i) the operation of the Partnership's facilities, (ii) plant availability and performance, (iii) the availability and price of energy commodities including natural gas and wood waste, (iv) the performance of counterparties in meeting their obligations under fuel supply, power purchase and other agreements, (v) competitive factors in the power industry, (vi) economic conditions, including in the markets served by the Partnership's facilities, (vii) changing demand for natural gas transportation on the TransCanada Canadian Mainline, (viii) ongoing compliance by the Partnership with its current debt covenants, (ix) developments within the North American capital markets, (x) the availability and cost of permanent long term financing in respect of acquisitions and investments, (xi) unanticipated maintenance and other expenditures, (xii) the Partnership's ability to successfully realize the benefits of its capital projects, (xiii) changes in regulatory and government decisions including changes to emission regulations, (xiv) waste heat availability and water flows, (xv) changes in existing and proposed tax and other legislation in Canada and the US and including changes in the Canada-US tax treaty, (xvi) the tax attributes of and implications of any acquisitions, (xvii) the availability and cost of equipment (xviii) the ability of the Partnership to adequately source alternative sources of supply of wood waste, (xix) the ability of the Partnership to obtain PPAs for the North Carolina facilities with satisfactory financial terms, (xx) the strategic review process could take more or less time than anticipated, and (xxi) risks and uncertainties noted under Outlook in respect of the forward looking statements and information noted in that section. See also Business Risks in this MD&A.

        Readers are cautioned not to place undue reliance on forward-looking statements as actual results could differ materially from the plans, expectations, estimates or intentions expressed in the forward-looking statements. Forward-looking statements are provided for the purpose of presenting information about management's current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. Except as required by law, the Partnership disclaims any intention and assumes no obligation to update any forward-looking statement.

Schedule V-51


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QUARTERLY UNIT TRADING INFORMATION

        The Partnership units trade on the Toronto Stock Exchange under the symbol CPA.UN.

 
  2010  
Three months ended
(unaudited)
  Mar. 31   Jun. 30   Sep. 30   Dec. 31   Annual  

Unit Price

                               
 

High

  $ 18.43   $ 18.14   $ 18.85   $ 19.02   $ 19.02  
 

Low

  $ 15.54   $ 15.05   $ 16.03   $ 17.11   $ 15.05  
 

Close

  $ 17.82   $ 16.30   $ 18.75   $ 17.95   $ 17.95  
                       
 

Volume traded (millions)

    4.8     5.1     4.2     4.4     18.5  
                       

 

 
  2009  
Three months ended
(unaudited)
  Mar. 31   Jun. 30   Sep. 30   Dec. 31   Annual  

Unit Price

                               
 

High

  $ 18.98   $ 16.21   $ 16.30   $ 15.77   $ 18.98  
 

Low

  $ 12.90   $ 11.65   $ 13.62   $ 13.35   $ 11.65  
 

Close

  $ 13.80   $ 15.25   $ 15.26   $ 15.48   $ 15.48  
                       

Volume traded (millions)

    3.3     9.2     4.3     6.2     23.0  
                       

        As at March 2, 2011, the Partnership had 56.0 million units outstanding. The weighted average number of units outstanding for the year ended December 31, 2010 was 55.0 million.


ADDITIONAL INFORMATION

        Additional information relating to Capital Power Income L.P. including the Partnership's Annual Information Form and continuous disclosure documents are available on SEDAR at www.sedar.com.

Schedule V-52


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Schedule VI

Unaudited Condensed Interim Financial Statements of CPILP
as at and for the Six Months Ended June 30, 2011


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Capital Power Income L.P.

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF INCOME (LOSS)

 
  Three months ended
June 30
  Six months ended
June 30
 
(unaudited)
  2011   2010   2011   2010  
(In millions of Canadian dollars except units and per unit amounts)
   
  Restated
(Note 7)

   
  Restated
(Note 7)

 

Revenues

  $ 130.3   $ 97.3   $ 261.5   $ 241.5  

Cost of fuel

    53.2     47.0     109.5     116.9  

Operating and maintenance expense

    27.6     24.2     52.4     46.8  
                   

    49.5     26.1     99.6     77.8  

Other costs (income)

                         

Depreciation

    22.5     24.5     45.5     47.9  

Administrative and other expenses

    9.6     1.6     13.8     5.6  

Finance costs (Note 4)

    10.6     10.0     21.5     21.4  

Finance income

        (1.8 )       (1.8 )
                   

Income (loss) before income tax

    6.8     (8.2 )   18.8     4.7  
                   

Income tax expense (recovery)

    1.1     (7.3 )   1.2     (10.9 )
                   

Net income (loss)

  $ 5.7   $ (0.9 ) $ 17.6   $ 15.6  
                   

Attributable to:

                         

Equity holders of the Partnership

    2.1     (4.5 )   10.5     8.4  

Preferred share dividends of a subsidiary company

    3.6     3.6     7.1     7.2  
                   

  $ 5.7   $ (0.9 ) $ 17.6   $ 15.6  
                   

Income (loss) per unit attributable to the equity holders of the Partnership (basic and diluted)

  $ 0.04   $ (0.08 ) $ 0.19   $ 0.15  
                   

Weighted average units outstanding (millions)

    56.4     54.7     56.2     54.5  
                   

See accompanying notes to the condensed interim consolidated financial statements.

Schedule VI-1


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Capital Power Income L.P.

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME (LOSS)

 
  Three months ended
June 30
  Six months ended
June 30
 
(unaudited)
  2011   2010   2011   2010  
(In millions of Canadian dollars)
   
  Restated
(Note 7)

   
  Restated
(Note 7)

 

Income (loss) for the period

  $ 5.7   $ (0.9 ) $ 17.6   $ 15.6  

Other comprehensive income (loss), net of income tax Cash flow hedges:

                         
 

Amortization of deferred gains on derivative instruments de-designated as cash flow hedges to income(1)

    (0.1 )   (0.1 )   (0.2 )   (0.2 )
 

Unrealized gains (losses) on derivative instruments designated as cash flow hedges(2)

    (4.9 )   4.1     (0.2 )   (24.8 )
 

Ineffective portion of cash flow hedges reclassified to income for the period(3)

    0.1     1.4     1.3     0.8  

Net investment in foreign operations:

                         
 

Gain (loss) on translating investment in foreign operations(4)

    (2.6 )   25.5     (14.2 )   7.0  

Available for sale financial asset:

                         
 

Net change in fair value of investment(5)

    1.0     0.5     0.9     2.1  
                   

    (6.5 )   31.4     (12.4 )   (15.1 )

Total comprehensive income (loss) for the period:

 
$

(0.8

)

$

30.5
 
$

5.2
 
$

0.5
 
                   

Attributable to:

                         

Equity holders of the Partnership

  $ (4.4 ) $ 26.9   $ (1.9 ) $ (6.7 )

Preferred share dividends of a subsidiary company

    3.6     3.6     7.1     7.2  
                   

(1)
Net of income tax expense of $nil million and $nil million (2010—$nil and $nil) for the three and six months ended June 30, 2011.

(2)
Net of income tax recovery of $1.7 million and $0.1 million (2010—$0.3 million and income tax recovery of $6.2 million) for the three and six months ended June 30, 2011.

(3)
Net of income tax expense of $0.1 million and $0.4 million (2010—$nil and $nil) for the three and six months ended June 30, 2011.

(4)
Includes income tax expense of $0.1 million and $0.8 million (2010—income tax recovery of $2.1 million and $0.4 million) for the three and six months ended June 30, 2011.

(5)
Net of income tax expense of $0.5 million and $0.5 million (2010—$0.3 million and $0.6 million) for the three and six months ended June 30, 2011.

See accompanying notes to the condensed interim consolidated financial statements.

Schedule VI-2


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Capital Power Income L.P.

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(unaudited)
  June 30,
2011
  December 31,
2010
 
(In millions of Canadian dollars)
   
  Restated
(Note 7)

 

ASSETS

             

Current assets

             
 

Cash and cash equivalents

  $ 12.8   $ 27.5  
 

Trade and other receivables

    48.8     52.5  
 

Inventories

    11.4     19.5  
 

Prepaids and other

    6.8     4.0  
 

Derivative assets (Note 3)

    13.0     10.4  
 

Assets classified as held for sale (Note 2)

    130.6      
           

Total current assets

    223.4     113.9  
           

Non-current assets

             
 

Derivative assets (Note 3)

    32.7     29.7  
 

Other financial assets

    69.4     72.5  
 

Deferred tax asset

    20.3     38.4  
 

Intangible assets

    270.4     290.1  
 

Property, plant and equipment

    835.9     958.5  
 

Goodwill

    19.7     43.8  
           

Total non-current assets

    1,248.4     1,433.0  
           

Total assets

  $ 1,471.8   $ 1,546.9  
           

LIABILITIES AND PARTNERS' EQUITY

             

Liabilities

             
 

Trade and other payables

  $ 59.4   $ 61.5  
 

Derivative liabilities (Note 3)

    23.1     21.1  
 

Liabilities classified as held for sale (Note 2)

    15.4      
           

Total current liabilities

    97.9     82.6  
           

Non-current liabilities

             
 

Derivative liabilities (Note 3)

    79.7     81.9  
 

Loans and borrowings

    675.5     704.5  
 

Deferred tax liabilities

    17.2     30.1  
 

Decommissioning provision

    39.6     50.1  
 

Other liabilities

    9.5     7.8  
           

Total non-current liabilities

    821.5     874.4  
           

Total liabilities

    919.4     957.0  
           

Equity attributable to equity holders of the Partnership

             
 

Partners' capital

    1,241.6     1,227.6  
 

Deficit

    (821.9 )   (782.9 )
 

Accumulated other comprehensive loss

    (87.5 )   (75.1 )
           

    332.2     369.6  

Preferred shares issued by a subsidiary company

    220.2     220.3  
           

Total equity

    552.4     589.9  
           
 

Contingencies (Note 6)

             

Total liabilities and equity

  $ 1,471.8   $ 1,546.9  
           

See accompanying notes to the condensed interim consolidated financial statements.

Schedule VI-3


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Capital Power Income L.P.

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' EQUITY

(unaudited)
(in millions of Canadian dollars)
  Partnership
capital
  Cumulative
translation
account*
  Available
for sale
financial
assets*
  Cash
flow
hedges*
  Deficit   Equity
attributable
to the
Partnership
  Non-
controlling
interests**
  Total  

Equity as at January 1, 2011

  $ 1,227.6   $ (29.6 ) $ 6.8   $ (52.3 ) $ (782.9 ) $ 369.6   $ 220.3   $ 589.9  

Income for the period

                    10.5     10.5     7.1     17.6  
                                   

Other comprehensive income (loss):

                                                 

Amortization of deferred gains on de-designated cash flow hedges

                (0.2 )       (0.2 )       (0.2 )

Unrealized gains on derivative instruments designated as cash flow hedges

                (0.2 )       (0.2 )       (0.2 )

Ineffective portion of cash flow hedges reclassified to income for the period

                1.3         1.3         1.3  

Loss on translating investment in foreign operations

        (14.2 )               (14.2 )       (14.2 )

Net change in fair value of investment

            0.9             0.9         0.9  
                                   

Total comprehensive income (loss)

        (14.2 )   0.9     0.9     10.5     (1.9 )   7.1     5.2  

Distributions

                    (49.5 )   (49.5 )       (49.5 )

Preferred share dividends paid

                            (6.5 )   (6.5 )

Tax on preferred share dividends

                            (0.7 )   (0.7 )

Issue of Partnership units

    14.0                     14.0         14.0  
                                   

Equity as at June 30, 2011

  $ 1,241.6   $ (43.8 ) $ 7.7   $ (51.4 ) $ (821.9 ) $ 332.2   $ 220.2   $ 552.4  
                                   

See accompanying notes to the condensed interim consolidated financial statements.

Schedule VI-4


Table of Contents


Capital Power Income L.P.

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' EQUITY (Continued)

 

(unaudited)
(in millions of Canadian dollars)
Restated (Note 7)
  Partnership
capital
  Cumulative
translation
account*
  Available
for sale
financial
assets*
  Cash
flow
hedges*
  Retained
earnings
  Equity
attributable
to the
Partnership
  Non-
controlling
interests**
  Total  

Equity as at January 1, 2010

  $ 1,200.6   $   $ (2.2 ) $ (3.4 ) $ (687.5 ) $ 507.5   $ 220.7   $ 728.2  

Income for the period

                    8.4     8.4     7.2     15.6  
                                   

Other comprehensive income (loss)

                                                 

Amortization of deferred gains on de-designated cash flow hedges

                (0.2 )       (0.2 )       (0.2 )

Unrealized losses on derivative instruments designated as cash flow hedges

                (24.8 )       (24.8 )       (24.8 )

Ineffective portion of cash flow hedges reclassified to income for the period

                0.8         0.8         0.8  

Loss on translating investment in foreign operations

        7.0                 7.0         7.0  

Net change in fair value of investment

            2.1             2.1         2.1  
                                   

Total comprehensive income (loss)

        7.0     2.1     (24.2 )   8.4     (6.7 )   7.2     0.5  

Distributions

                    (48.1 )   (48.1 )       (48.1 )

Preferred share dividends paid

                            (6.5 )   (6.5 )

Tax on preferred share dividends

                            (0.9 )   (0.9 )

Issue of Partnership units

    13.5                     13.5         13.5  
                                   

Equity as at June 30, 2010

  $ 1,214.1   $ 7.0   $ (0.1 ) $ (27.6 ) $ (727.2 ) $ 466.2   $ 220.5   $ 686.7  
                                   

*
Accumulated other comprehensive loss

**
Preferred share dividends of a subsidiary company

See accompanying notes to the condensed interim consolidated financial statements.

Schedule VI-5


Table of Contents


Capital Power Income L.P.

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CASH FLOWS

 
  Six months
ended June 30
 
(unaudited)
  2011   2010  
(In millions of Canadian dollars)
   
  Restated
(Note 7)

 

Operating activities

             

Income before income tax for the period

  $ 18.8   $ 4.7  

Adjustments:

             
 

Depreciation

    45.5     47.9  
 

Fair value changes on derivative instruments

    (4.7 )   20.5  
 

Preferred share dividends paid

    (6.5 )   (6.5 )
 

Principal repayments on finance lease receivable

    1.1     0.9  
 

Deferred revenue

    1.2     1.6  
 

Income taxes paid

    (3.1 )   (3.0 )
 

Interest expense

    19.4     19.3  
 

Interest income

        (1.8 )
 

Interest paid

    (19.8 )   (19.3 )
 

Other

    1.6     0.8  
           

    53.5     65.1  

Decrease in operating working capital

    (0.9 )   (20.2 )
           

Cash provided by operating activities

    52.6     44.9  
           

Investing activities

             

Additions to property, plant and equipment

    (13.3 )   (12.8 )

Change in non-operating working capital

    (1.1 )   (4.0 )
           

Cash used in investing activities

    (14.4 )   (16.8 )
           

Financing activities

             

Distributions paid

    (35.4 )   (34.5 )

Net borrowings (repayments) under credit facilities

    (16.8 )   8.5  

Repayment of loans and borrowings

        (0.7 )
           

Cash used in financing activities

    (52.2 )   (26.7 )
           

Foreign exchange (losses) gains on cash held in a foreign currency

    (0.7 )   0.2  

Decrease in cash and cash equivalents

    (14.7 )   1.6  

Cash and cash equivalents, beginning of period

    27.5     9.5  
           

Cash and cash equivalents, end of period

  $ 12.8   $ 11.1  
           

See accompanying notes to the condensed interim consolidated financial statements.

Schedule VI-6


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

1. Basis of presentation and conversion to IFRS

        These condensed interim consolidated financial statements have been prepared by management of the General Partner in accordance with International Financial Reporting Standards (IFRS)—International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board and adopted by the Canadian Institute of Chartered Accountants applicable companies for years beginning on or after January 1, 2011. For prior reporting periods up to and including the year ended December 31, 2010, the Partnership prepared its condensed interim consolidated financial statements in accordance with Canadian generally accepted accounting principles (GAAP). The condensed consolidated interim financial statements do not include all of the information required for full annual financial statements.

        An explanation of how the transition to IFRS has affected the financial position, financial performance and cash flows of the Partnership is provided in note 7. This note includes reconciliations of equity and total comprehensive income for comparative periods reported under previous Canadian GAAP to those reported under IFRSs. A reconciliation of equity at the date of transition reported under previous Canadian GAAP to equity reported under IFRSs is included in the condensed interim consolidated financial statements for the first quarter of 2011.

        The Partnership's condensed interim consolidated financial statements are prepared under the historical cost convention, except for the revaluation of the Partnership's derivative instruments, cash and available for sale financial assets, which are recognized at fair value and certain property, plant and equipment which is recognized at deemed cost as fair value, at January 1, 2010.

        Quarterly revenues, income and cash provided by operating activities are affected by seasonal contract pricing, seasonal weather conditions, fluctuations in United States (US) dollar exchange rates, fulfillment of firm energy requirements, natural gas prices, waste heat availability and planned and unplanned plant outages, as well as items outside of the normal course of operations. Quarterly income is also affected by unrealized foreign exchange gains and losses and fair value changes in derivative instruments. The California plants normally generate the majority of their operating margin during the summer months when the plants can earn performance bonuses. Additionally, the plants located on Naval bases earn approximately 75% of their capacity revenue during these months. Revenues, income and cash provided by operating activities from the Partnership's Ontario plants are generally higher in the winter months (October to March) and lower in the summer months (April to September) due to seasonal pricing under the power purchase arrangements. Revenues and income from the Partnership's hydroelectric plants are generally higher in the spring months due to seasonally higher water flows.


Use of judgements and estimates

        The preparation of the Partnership's condensed interim consolidated financial statements in accordance with IFRS requires management to make judgements, estimates and assumptions that affect the reported amounts of income, expenses, assets and liabilities as well as the disclosure of contingent assets and liabilities at the date of the condensed interim consolidated financial statements.

        The Partnership reviews its estimates and assumptions on an ongoing basis and uses the most current information available and exercises careful judgement in making these estimates and

Schedule VI-7


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

1. Basis of presentation and conversion to IFRS (Continued)


assumptions. Adjustments to previous estimates, which may be material, will be recorded in the period they become known. Actual results may differ from these estimates.

        In the opinion of management of the Partnership's General Partner, these condensed interim consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Partnership's accounting policies.


Future accounting standards

        A number of new standards, and amendments to standards and interpretations, are not yet effective for the quarter ended June 30, 2011 and have not been applied in preparing the unaudited condensed interim consolidated financial statements. The following standards and interpretations have been issued by the International Accounting Standards Board and the International Financial Reporting Interpretations Committees with effective dates relating to the annual periods starting on or after the effective dates as follows:

International Accounting Standards (IAS/IFRS)
  Effective Date

IFRS 9—Financial Instruments

  January 1, 2013

IAS 12—Income Taxes

 
January 1, 2012

IFRS 10—Consolidated Financial Statements

 
January 1, 2013

IFRS 11—Joint Arrangements

 
January 1, 2013

IFRS 12—Disclosures of Interests in Other Entities

 
January 1, 2013

IFRS 13—Fair Value Measurement

 
January 1, 2013

IAS 1—Presentation of Financial Statements

 
July 1, 2012

        IFRS 9 applies to the classification and measurement of financial assets and financial liabilities. It is the first of three phases of a project to develop standards to replace IAS 39—Financial Instruments and was initiated in response to the crisis in financial markets.

        The amendments to IAS 12 relate to the measurement of deferred taxes for investment property, PP&E and intangible assets carried at fair value.

        IFRS 10 replaces IAS 27 Consolidated and Separate Financial Statements and SIC—12 Consolidation—Special Purpose Entities. IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements. It provides a single consolidation model that identifies control as the basis for consolidation for all types of entities. IFRS 12 provides comprehensive disclosure requirements for all forms of interests in other entities, including subsidiaries, joint arrangements, associates and special purpose vehicles.

        IFRS 11 supersedes IAS 31—Interests in Joint Ventures and SIC 13—Jointly Controlled Entities—Non-Monetary Contributions by Venturers. The standard requires a single method to account for

Schedule VI-8


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

1. Basis of presentation and conversion to IFRS (Continued)


interests in jointly controlled entities. All joint ventures are required to be recognized as an investment and be accounted for on an equity basis.

        IFRS 13 defines fair value, sets out in a single IFRS a framework for measuring fair value and requires disclosures about fair value measurements. IFRS 13 applies when other IFRSs require or permit fair value measurements. It does not introduce any new requirements to measure an asset or a liability at fair value, change what is measured at fair value in IFRSs or address how to present changes in fair value.

        The amendments to IAS 1 provide improvements to the presentation of components of other comprehensive income. It requires entities to group items within other comprehensive income that may be reclassified to profit or loss.

        The extent of the impact of adoption of these standards and interpretations on the consolidated financial statements of the Partnership has not been determined.

2. Assets and liabilities held for sale

        On June 20, 2011 the Partnership agreed to sell its Southport and Roxboro facilities (the disposal group) to an affiliate of Capital Power Corporation for approximately $121 million concurrent with and contingent upon the sale of the Partnership to Atlantic Power Corporation. The sale is expected to close in the fourth quarter of 2011. The Partnership will not have any continuing involvement in the disposal group after the disposal transaction. Accordingly, the assets and liabilities of the disposal group at June 30, 2011 have been segregated and presented as assets and liabilities held for sale as follows:

 
  June 30,
2011
 

Assets held for sale

       
 

Accounts receivable

  $ 6.0  
 

Inventories

    7.3  
 

Prepaids and other

     
 

Property, plant and equipment

    90.5  
 

Deferred taxes

    4.0  
 

Goodwill

    22.8  
       

  $ 130.6  
       

Liabilities held for sale

       
 

Accounts payable

  $ 3.0  
 

Decommissioning provision

    12.0  
 

Deferred taxes

     
 

Other liabilities

    0.4  
       

  $ 15.4  
       

Schedule VI-9


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

2. Assets and liabilities held for sale (Continued)

        No impairment loss was recognized in the condensed statement of comprehensive income for the three and six months ended June 30, 2011 as the carrying amount of the disposal group is less than its fair value less cost to sell.

        At June 30, 2011, accumulated other comprehensive loss included accumulated foreign exchange losses of $9.4 million related to the Partnership's investment in the disposal group that will be reclassified to net income (loss) on disposal.

3. Derivative instruments

        Derivative instruments are held to manage financial risk related to energy procurement and treasury management. All derivative instruments, including embedded derivatives, are classified as held at fair value through profit or loss and are recorded at fair value on the statement of financial position as derivative instruments assets and derivative instruments liabilities unless exempted from derivative treatment as a normal purchase, sale or usage. All changes in their fair value are recorded in the condensed interim consolidated statement of income.

        The derivative instruments assets and liabilities used for risk management purposes consist of the following:

 
  June 30, 2011  
 
  Natural gas   Foreign exchange    
 
 
  Hedges   Non-hedges   Non-hedges   Total  

Derivative instruments assets:

                         
 

Current

  $   $   $ 13.0   $ 13.0  
 

Non-current

        0.2     32.5     32.7  

Derivative instruments liabilities:

                         
 

Current

    (17.8 )   (1.9 )   (3.4 )   (23.1 )
 

Non-current

    (74.6 )   (0.2 )   (4.9 )   (79.7 )
                   

  $ (92.4 ) $ (1.9 ) $ 37.2   $ (57.1 )
                   

Net notional amounts:

                         
 

Gigajoules (GJs)(millions)

    34.7     4.4              
 

US foreign exchange (US dollars in millions)

                297.3        
 

Contract terms (years)

    5.5     0.3 to 1.5     0.2 to 5.0        

Schedule VI-10


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

3. Derivative instruments (Continued)


 
  December 31, 2010  
 
  Natural gas   Foreign
exchange
   
 
 
  Hedges   Non-hedges   Non-hedges   Total  

Derivative instruments assets:

                         
 

Current

  $   $   $ 10.4   $ 10.4  
 

Non-current

            29.7     29.7  

Derivative instruments liabilities:

                         
 

Current

    (16.2 )   (3.0 )   (1.9 )   (21.1 )
 

Non-current

    (76.9 )       (5.0 )   (81.9 )
                   

  $ (93.1 ) $ (3.0 ) $ 33.2   $ (62.9 )
                   

Net notional amounts:

                         
 

Gigajoules (GJs)(millions)

    37.8     6.5              
 

US foreign exchange (US dollars in millions)

                309.0        
 

Contract terms (years)

    6.0     0.8 to 2.0     0.2 to 5.5        

        Unrealized and realized pre-tax gains and losses on derivative instruments recognized in the condensed interim consolidated statement of income and other comprehensive income were:

 
   
  Three months ended
June 30
  Six months ended
June 30
 
 
  Financial statement category  
 
  2011   2010   2011   2010  

Foreign exchange non-hedges

  Revenue   $ 3.1   $ (18.6 ) $ 10.3   $ (10.0 )

Natural gas non-hedges

  Cost of fuel     1.3     2.4     2.0     (5.9 )

Natural gas hedges—ineffective portion

  Cost of fuel     (0.5 )   (1.4 )   (1.7 )   (0.8 )

Natural gas hedges—effective portion

  Other comprehensive income (loss)     (6.7 )   5.8     1.1     (30.2 )
                       

        The Partnership has elected to apply hedge accounting on certain derivative instruments it uses to manage commodity price risk relating to natural gas prices. For the three and six months ended June 30, 2011, the change in the fair value of the ineffective portion of hedging derivatives required to be recognized in the condensed interim consolidated statement of income was $0.5 million and $1.7 million respectively.

Schedule VI-11


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

3. Derivative instruments (Continued)

        Net after tax gains and losses on derivative instruments designated as cash flow hedges are included in accumulated other comprehensive income at June 30, 2011. Losses of $51.4 million are expected to settle and be reclassified to the condensed interim consolidated statement of income in the following periods:

 
  June 30,
2011
 

Within one year

  $ (11.4 )

Between 1 to 5 years

    (36.2 )

After more than 5 years

    (3.8 )
       

  $ (51.4 )
       

        The Partnership's cash flow hedges extend up to 2016.

4. Finance costs

 
  Three months ended
June 30
  Six months ended
June 30
 
 
  2011   2010   2011   2010  

Interest on long-term debt

  $ 9.5   $ 9.7   $ 19.1   $ 19.3  

Foreign exchange losses

        (0.5 )       0.2  

Accretion and amortization

    0.7     0.6     1.2     1.3  

Other

    0.4     0.2     1.2     0.6  
                   

  $ 10.6   $ 10.0   $ 21.5   $ 21.4  
                   

5. Segment information

        The Partnership operates in one reportable business segment involved in the operation of electrical generation plants within British Columbia, Ontario and in the US in California, Colorado, Illinois, New Jersey, New York, North Carolina and Washington State.


Geographic information

 
  Three months ended
June 30, 2011
  Three months ended
June 30, 2010
 
 
  Canada   US   Total   Canada   US   Total  

Revenue

  $ 51.3   $ 79.0   $ 130.3   $ 29.3   $ 68.0   $ 97.3  
                           
 
  Six months ended
June 30, 2011
  Six months ended
June 30, 2010
 

 

 

Canada

 

US

 

Total

 

Canada

 

US

 

Total

 

Revenue

  $ 116.0   $ 145.5   $ 261.5   $ 97.2   $ 144.3   $ 241.5  
                           

Schedule VI-12


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

5. Segment information (Continued)


 
  As at June 30, 2011   As at December 31, 2010  
 
  Canada   US   Total   Canada   US   Total  

Assets

                                     
 

PP&E

  $ 436.7   $ 399.2   $ 835.9   $ 448.5   $ 510.0   $ 958.5  
 

Goodwill

        19.7     19.7         43.8     43.8  
 

Intangible assets

    32.1     238.3     270.4     33.6     256.5     290.1  
                           

  $ 468.8   $ 657.2   $ 1,126.0   $ 482.1   $ 810.3   $ 1,292.4  
                           
 
  Six months ended
June 30, 2011
  Six months ended
June 30, 2010
 

 

 

Canada

 

US

 

Total

 

Canada

 

US

 

Total

 

Capital additions

  $ 4.4   $ 8.9   $ 13.3   $ 4.9   $ 7.9   $ 12.8  
                           

6. Contingencies

        The Partnership and Atlantic Power Corporation (Atlantic Power) have entered into an agreement pursuant to which Atlantic Power would acquire, directly and indirectly, all of the outstanding limited partnership units of the Partnership (the "Transaction"). If the Transaction fails to receive unitholder approval, the Partnership will reimburse Atlantic Power for its costs associated with the Transaction up to $8 million. Further, any solicitation or recommendation of a competing proposal or offer prior to completion of this agreement will result in the payment of a $35 million termination fee. There is no possibility of any reimbursement of these amounts once paid.

        Concurrent with and contingent upon the completion of the Transaction, the Partnership will pay $8.5 million to affiliates of Capital Power Corporation for the termination of certain management and operations agreements and will pay success fees of approximately $12 million to its financial advisors.

7. Transition to IFRS

        For all periods up to and including the year ended December 31, 2010, the Partnership prepared its financial statements in accordance with previous Canadian GAAP.

        The Partnership has prepared financial statements which comply with IFRS applicable for periods beginning on or after January 1, 2010 as described in note 2. In preparing these financial statements, the Partnership's opening statement of financial position was prepared as at January 1, 2010, the Partnership's date of transition to IFRS. This note explains the principal adjustments made by the Partnership in restating its previously published Canadian GAAP financial statements for the three and six months ended June 30, 2010. Explanations of the principal adjustments made by the Partnership in restating its Canadian GAAP Statement of Financial Position as at January 1, 2010 and its financial statements for the twelve months ended December 31, 2010 are included in the condensed interim

Schedule VI-13


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

7. Transition to IFRS (Continued)


consolidated financial statements for the first quarter of 2011. The Partnership has applied the following optional exemptions in its transition from Canadian GAAP to IFRS:

Schedule VI-14


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

7. Transition to IFRS (Continued)

Reconciliation of equity

Reconciliation of equity—June 30, 2010

 
  Canadian
GAAP
  IAS 16
and
37 (a)
  IAS 36 (b)   IFRS 1 (c)   Other
impacts (d)
  Presentation
adjustment
  IFRS  

ASSETS

                                           

Current assets

                                           
 

Cash and cash equivalents

  $ 11.1   $   $   $   $   $   $ 11.1  
 

Trade and other receivables

    67.1                         67.1  
 

Inventories

    39.1                         39.1  
 

Prepaids and other

    7.3                         7.3  
 

Future income tax asset

    1.8                     (1.8 )    
 

Derivative assets

    4.5                         4.5  
                               

Total current assets

    130.9                     (1.8 )   129.1  
                               

Non-current assets

                                           
 

Derivative assets

    19.6                         19.6  
 

Other financial assets

    49.2                 (0.2 )   (1.1 )   47.9  
 

Deferred tax asset

    41.1                 (3.6 )   1.8     39.3  
 

Intangible assets

    321.1         (0.9 )           1.1     321.3  
 

Property, plant and equipment

    1,047.8     (20.6 )   (21.3 )   57.6             1,063.5  
 

Goodwill

    48.2         (1.2 )               47.0  
                               

Total non-current assets

    1,527.0     (20.6 )   (23.4 )   57.6     (3.8 )   1.8     1,538.6  
                               

Total assets

  $ 1,657.9   $ (20.6 ) $ (23.4 ) $ 57.6   $ (3.8 ) $   $ 1,667.7  
                               

LIABILITIES AND PARTNERS' EQUITY

                                           

Liabilities

                                           
 

Trade and other payables

  $ 64.8   $   $   $   $   $     64.8  
 

Derivative liabilities

    14.4                         14.4  
 

Future income tax liability

    0.3                     (0.3 )    
 

Loans and borrowings

    0.7                         0.7  
                               

Total current liabilities

    80.2                     (0.3 )   79.9  
                               

Non-current liabilities

                                           
 

Derivative liabilities

    60.4                         60.4  
 

Loans and borrowings

    734.2                         734.2  
 

Decommissioning provision

        21.1                 29.5     50.6  
 

Deferred tax liabilities

    52.7                 (4.3 )   0.3     48.7  
 

Other liabilities

    36.6                     (29.5 )   7.1  
                               

Total non-current liabilities

    883.9     21.1             (4.3 )   0.3     901.0  
                               

Total liabilities

    964.1     21.1             (4.3 )       980.9  
                               

Equity attributable to equity holders of the Partnership

                                           
 

Partners' capital

    1,214.1                         1,214.1  
 

Deficit

    (586.5 )   (41.4 )   (23.1 )   (75.5 )   (0.7 )       (727.2 )
 

Accumulated other comprehensive loss

    (153.5 )   (0.3 )   (0.3 )   133.1     0.4         (20.6 )
                               

    474.1     (41.7 )   (23.4 )   57.6     (0.3 )       466.3  

Preferred shares issued by a subsidiary company

    219.7                 0.8         220.5  
                               

Total equity

    693.8     (41.7 )   (23.4 )   57.6     0.5         686.8  
                               

Total liabilities and equity

  $ 1,657.9   $ (20.6 ) $ (23.4 ) $ 57.6   $ (3.8 ) $   $ 1,667.7  
                               

Schedule VI-15


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

7. Transition to IFRS (Continued)

Notes to the equity reconciliations

a)    IAS 16 Property, plant and equipment (PP&E) & IAS 37 provisions

        IFRS are more specific with respect to the level at which component accounting is required and mandates that overhauls embedded within the initial carrying amount of a component must be treated as a separate component.

        In accordance with IAS 16, PP&E has decreased by $36.3 million at June 30, 2010 as a result of identifying the significant components and calculating the adjustment to accumulated depreciation for the components' useful lives as well as derecognizing the overhauls that were inherent in the original turbines and a subsequent overhaul has been performed.

        In accordance with IAS 37, provisions are required to be measured at the best estimate of the expected expenditure using discount rates appropriate for each liability. Under Canadian GAAP the provision was measured at fair value. The provision is to be re-measured at each reporting period for any changes in cash flow estimates, timing of decommissioning activity and discount rates. Accordingly, the Partnership re-measured its asset retirement obligations with revised discount rates for all decommissioning liabilities. The re-measurement of the decommissioning liabilities resulted in an increase of $21.1 million at June 30, 2010 to the non-current provision. The re-measurement of the decommissioning liability also resulted in an increase to the associated PP&E of $15.7 million at June 30, 2010.

        These adjustments resulted in an increase to the deficit of $41.4 million at June 30, 2010.

        Accumulated other comprehensive loss (AOCL) increased by $0.3 million at June 30, 2010 as a result of translating the IFRS adjustments for the Partnership's operations with a US dollar functional currency.

b)    IAS 36 Impairment

        In accordance with IAS 36, the Partnership reviewed the recoverable amount for its CGUs with allocated goodwill at both the date of transition and in the third quarter of 2010. IAS 36 also requires that impairment testing be done on a CGU level and requires that goodwill be allocated to the CGU level and included in the impairment test for each plant. The Partnership has determined its CGUs to be at the plant level. For these CGU's, management assessed whether there were any triggering events at December 31, 2010. The recoverable amounts were calculated on a fair value less cost to sell basis, using discounted cash flow models based on the Partnership's long term planning model. Previously under GAAP, the carrying values were compared to the undiscounted cash flows first and if the undiscounted cash flows exceeded carrying value then no further steps were taken.

        As a result of the changes to the determination of recoverable amounts and the allocation of the goodwill to the CGUs, the Partnership recorded total impairments of $23.7 million at December 31, 2009, which includes $12.9 million for Roxboro and $8.0 million for Greeley. The impairments at Roxboro and Greeley were the result of weakening economic conditions in their respective markets.

Schedule VI-16


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

7. Transition to IFRS (Continued)


The Partnership decreased its intangible assets, PP&E and goodwill $0.9 million, $21.3 million and $1.2 million respectively at June 30, 2010.

        These adjustments resulted in an increase to the deficit of $23.1 million at June 30, 2010.

        AOCL decreased by $0.3 million at June 30, 2010 as a result of translating the IFRS adjustments for the Partnership's operations with a US dollar functional currency.

c)     IFRS 1 First time adoption of IFRS

        As a result of the Partnership taking the IFRS 1 election to use fair value as deemed cost for the PP&E at Manchief and Curtis Palmer, the PP&E balance increased by $57.6 million at June 30, 2010. The change in the value of the increase to fair value subsequent to January 1, 2010 is a result of depreciation of the increase to fair value and foreign exchange impacts. The aggregate fair value deemed as cost for the PP&E of these plants at January 1, 2010 was $210.2 million.

        As a result of the Partnership taking the IFRS 1 election to deem the balance for the cumulative translation amount to be $nil on January 1, 2010, the accumulated other comprehensive loss decreased by $131.9 million.

        These adjustments resulted in an increase to the deficit of $75.5 million at June 30, 2010.

        AOCL decreased by $1.2 million at June 30, 2010 as a result of translating the fair value as deemed cost election taken by the Partnership's operations with a US dollar functional currency.

d)    Other impacts

        In accordance with IAS 39, Financial Instruments: Recognition and Measurement, financial assets available for sale must be measured at fair value. Under Canadian GAAP, the investment in PERH was carried at the lower of historic cost and fair value. IAS 39 requires financial assets to be measured at fair value even if it is not traded in an active market. Fair value was established using the market price of Primary Energy Recycling Corporation (PERC), a publicly traded company whose sole asset is an investment in PERH. As a result of measuring the investment in PERH at its fair value, other financial assets were reduced by $0.2 million at June 30, 2010. As this adjustment is unrealized, the offset is included in AOCL.

        In accordance with IAS 39, hedge effectiveness testing must incorporate the Partnerships' credit risk which resulted in the Partnership's deficit increasing by $1.6 million at June 30, 2010. As this adjustment is unrealized, the offset is to the AOCL, which are recorded net of tax.

        The tax impacts recorded against the above adjustments was $nil at June 30, 2010.

        Other impacts also include the impact to the deferred tax assets and deferred tax liabilities resulting from all of the IFRS transition adjustments discussed above. The deferred tax asset decreased by $3.6 million at June 30, 2010. The deferred tax liability decreased by $4.3 million at June 30, 2010.

        AOCL increased by $1.2 million at June 30, 2010 as a result of translating the other adjustments for the Partnership's operations with a US dollar functional currency.

Schedule VI-17


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

7. Transition to IFRS (Continued)


Reconciliation of total comprehensive income (loss)

Reconciliation of total comprehensive income—three months ended June 30, 2010

 
  Canadian
GAAP
  IAS 16
and
37
  IAS 36
(a)
  IFRS 1   Other
impacts
(b)
  Presentation
adjustment
  IFRS  

Revenues

  $ 97.3   $   $   $   $   $   $ 97.3  

Cost of fuel

    46.6                 0.4         47.0  

Operating and maintenance expense

    24.2                         24.2  
                               

    26.5                 (0.4 )       26.1  
                               

Other costs (income)

                                           

Depreciation

    26.3     (0.9 )   (0.3 )   0.9         (1.5 )   24.5  

Administrative and other expenses

    1.6                         1.6  

Finance costs

    8.0     (1.3 )               3.3     10.0  

Finance income

                        (1.8 )   (1.8 )
                               

Income (loss) before income tax

    (9.4 )   2.2     0.3     (0.9 )   (0.4 )       (8.2 )
                               

Income tax recovery

    (4.0 )               (3.3 )       (7.3 )
                               

Income (loss) for the period

    (5.4 )   2.2     0.3     (0.9 )   2.9         (0.9 )
                               

Other comprehensive income (loss)

    32.9     (1.2 )   (1.1 )   4.2     (3.4 )       31.4  
                               

Total comprehensive income (loss)

  $ 27.5   $ 1.0   $ (0.8 ) $ 3.3   $ (0.5 ) $   $ 30.5  
                               

Attributable to:

                                           

Equity holders of the Partnership

  $ 23.9   $ 1.0   $ (0.8 ) $ 3.3   $ (0.5 ) $   $ 26.9  

Preferred share dividends of a subsidiary company

    3.6                         3.6  
                               

Schedule VI-18


Table of Contents


Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

7. Transition to IFRS (Continued)


Reconciliation of total comprehensive income—six months ended June 30, 2010

 
  Canadian
GAAP
  IAS 16
and
37
  IAS 36
(a)
  IFRS 1   Other
impacts
(b)
  Presentation
adjustment
  IFRS  

Revenues

  $ 241.5   $   $   $   $   $   $ 241.5  

Cost of fuel

    117.3                 (0.4 )       116.9  

Operating and maintenance expense

    46.8                         46.8  
                               

    77.4                 0.4         77.8  
                               

Other costs (income)

                                           

Depreciation

    49.8     (1.2 )   (0.5 )   1.7         (1.9 )   47.9  

Administrative and other expenses

    5.6                         5.6  

Finance costs

    19.0     (1.3 )               3.7     21.4  

Finance income

                        (1.8 )   (1.8 )
                               

Income (loss) before income tax

    3.0     2.5     0.5     (1.7 )   0.4         4.7  
                               

Income tax recovery

    (9.5 )               (1.4 )       (10.9 )
                               

Income for the period

    12.5     2.5     0.5     (1.7 )   1.8         15.6  
                               

Other comprehensive income (loss)

    (16.1 )   (0.2 )   (0.3 )   1.1     0.4         (15.1 )
                               

Total comprehensive (income) loss

  $ (3.6 ) $ 2.3   $ 0.2   $ (0.6 ) $ 2.2   $   $ 0.5  
                               

Attributable to:

                                           

Equity holders of the Partnership

  $ (10.8 ) $ 2.3   $ 0.2   $ (0.6 ) $ 2.2   $   $ (6.7 )

Preferred share dividends of a subsidiary company

    7.2                         7.2  
                               


Notes to the total comprehensive income reconciliations

a)    IAS 36 Impairment

        The impact to depreciation as a result of implementing IAS 36 is a decrease of $0.3 million and $0.5 million for the three and six months ended June 30, 2010, respectively.

        OCL increased by $1.1 million and $0.3 million for the three and six months ended June 30, 2010, respectively as a result of translating the IAS 36 adjustments for the Partnership's operations with a US dollar functional currency.

b)    Other impacts

        The impact of incorporating the Partnership's credit risk in the hedge effectiveness testing, under IAS 39, is an increase to the cost of fuel of $0.4 million and a decrease to fuel of $0.4 million for the three and six months ended June 30, 2010, respectively. The offset is an increase to OCL.

Schedule VI-19


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Capital Power Income L.P.

Notes to the Condensed Interim Consolidated Financial Statements (Continued)

June 30, 2011

(Unaudited, tabular amounts in millions of Canadian dollars)

7. Transition to IFRS (Continued)

        The combined impact of these adjustments to income tax recovery for the three and six months ended June 30, 2010 is an increase of $3.3 million and $1.4 million, respectively.

        The remaining adjustments impact OCL:


Summary of other comprehensive loss adjustments

 
  Three months
ended June 30,
2010
  Six months
ended June 30,
2010
 

IAS 39—Hedge effectiveness

    0.4     (0.4 )

IAS 39—PERH fair value

    0.5     2.0  

Foreign exchange impacts

    (4.3 )   (1.2 )
           

    (3.4 )   0.4  
           

Schedule VI-20


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Schedule VII

Management's Discussion and Analysis of CPILP
for the Six Months Ended June 30, 2011


Table of Contents

Capital Power Income L.P.
Management's Discussion and Analysis
For the Six Months Ended June 30, 2011

        This management's discussion and analysis (MD&A) is dated July 25, 2011 and should be read in conjunction with the unaudited condensed interim consolidated financial statements of Capital Power Income L.P. (collectively with its subsidiaries, the Partnership, unless otherwise specifically stated) for the six months ended June 30, 2011 and the audited consolidated financial statements and MD&A of the Partnership for the year ended December 31, 2010. Additional information relating to the Partnership, including the 2010 Annual Information Form and other continuous disclosure documents are available on SEDAR at www.sedar.com. This discussion contains certain forward-looking information and readers are advised to read this discussion in conjunction with the cautionary statement regarding forward-looking information and statements located toward the end of this MD&A.

        CPI Income Services Ltd., the general partner of the Partnership (the General Partner), is responsible for management of the Partnership. The General Partner is a wholly-owned subsidiary of CPI Investments Inc. (Investments). EPCOR Utilities Inc. (collectively with its subsidiaries, EPCOR) owns 51 voting, non-participating shares of Investments and Capital Power Corporation (collectively with its subsidiaries, CPC) indirectly owns 49 voting, participating shares of Investments. The Board of the General Partner (the Board) declares the cash distributions to the Partnership's unitholders. The General Partner has engaged CP Regional Power Services Limited Partnership and Capital Power Operations (USA) Inc. (collectively herein, the Manager), both subsidiaries of CPC, to perform management and administrative services for the Partnership and to operate and maintain the power plants pursuant to management and operations agreements. The Audit Committee of the Board is to review and approve the interim MD&A of the Partnership in accordance with the Audit Committee's terms of reference. The Audit Committee has reviewed and approved the contents of this interim MD&A.


SIGNIFICANT EVENTS

Atlantic Power Corporation agrees to acquire Capital Power Income L.P.

        On June 20, 2011, the Partnership and Atlantic Power Corporation (Atlantic Power) jointly announced that they had entered into an arrangement agreement pursuant to which Atlantic Power would acquire, directly and indirectly, all of the outstanding limited partnership units of the Partnership for $19.40 per limited partnership unit, payable in cash or shares of Atlantic Power (the "Transaction").

        The Partnership intends to continue paying its monthly distribution, equal to $1.76 per limited partnership unit on an annual basis, through the month preceding the month of closing of the Transaction with Atlantic Power. The Transaction is expected to be completed in the fourth quarter of 2011, subject to customary approvals including unitholder and shareholder approvals.

        Concurrent with and contingent upon the completion of the Transaction, the Partnership will sell Roxboro and Southport to an affiliate of CPC. The Transaction values Southport and Roxboro at approximately $121 million. This Transaction will have the effect of reducing the number of Partnership units outstanding by approximately 6.2 million units.

        Additionally, concurrent with and contingent upon the completion of the Transaction, the management agreements between the Manager and the Partnership will be terminated (or assigned to Atlantic Power) for a fee of $8.5 million payable by the Partnership to CPC and a fee of $1.5 million payable by Atlantic Power to CPC. Atlantic Power will assume the management of the Partnership.

        The Transaction is a result of the strategic review process undertaken by the Partnership that was publicly announced on October 5, 2010. The strategic review process was undertaken by a special

Schedule VII-1


Table of Contents

committee of independent directors of the General Partner in co-operation with CPC and included an evaluation of a broad range of alternatives for the Partnership.

Power Purchase Agreements finalized for the North Carolina plants

        In June 2011, the Partnership executed ten year power purchase agreements (PPAs) for Southport and Roxboro, replacing an interim PPA that was effective April 1, 2011, under terms that were largely consistent with the interim PPA. Operating margin for the plants is expected to average US$15 million per year during the 10 year terms of the final PPAs, with higher earnings expected in earlier years.

Power Purchase Agreement amendment for the Calstock plant

        The PPA for Calstock was amended effective May 1, 2011 to increase the price for power delivered during peak power demand periods and to reduce the power the PPA counterparty is required to purchase during periods of low power demand. The amendment to the PPA is expected to result in an increase in the operating margin of Calstock of approximately $4 million to $5 million annually for the five year term.

Termination of Distribution Reinvestment Plans

        The Partnership terminated its Premium Distribution and Distribution Reinvestment Plan on June 30, 2011.


CONSOLIDATED RESULTS OF OPERATIONS

(millions of dollars) (unaudited)
  Three
months
  Six
months
 

Funds from operations for the three and six months ended June 30, 2010

    30.3     67.2  
           

Higher operating margin at Curtis Palmer

    4.5     3.7  

Higher operating margin at the North Carolina plants

    2.7     2.9  

Decrease (increase) in current income taxes

    2.2     (0.6 )

Strategic review and Transaction related costs

    (5.7 )   (5.7 )

Interest from Equistar and reversal of provision in 2010

    (3.9 )   (3.9 )

Lower operating margin at the BC Hydroelectric plants

    (1.8 )   (2.6 )

Lower operating margin at Northeast US natural gas plants

    (1.5 )   (1.0 )

Lower operating margin at the California plants

    (0.5 )   (1.8 )

Lower operating margin at the Northwest US plants

    (0.4 )   (1.9 )

Lower operating margin at the Ontario plants

    (0.2 )   (2.1 )

Other

    1.1     (0.5 )
           

Funds from operations for the three and six months ended June 30, 2011

    26.8     53.7  
           

        The Partnership reported funds from operations of $26.8 million or $0.48 per unit for the quarter ended June 30, 2011 compared to $30.3 million or $0.55 per unit for the same period in 2010. Funds from operations and funds from operations per unit are defined below under Non-IFRS Measures. The $3.5 million decrease in funds from operations for the second quarter of 2011 compared to the second quarter of 2010 was primarily due to the following:

Schedule VII-2


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        Decreases were partially offset by the following:

        The Partnership reported funds from operations of $53.7 million or $0.96 per unit for the six months ended June 30, 2011 compared to $67.2 million or $1.23 per unit for the same period in 2010. Funds from operations and funds from operations per unit are defined below under Non-IFRS Measures. The $13.5 million decrease in funds from operations for the six months ended June 30, 2011 compared to the same period in 2010 was primarily due to the items described above for the current quarter, as well as the following:

Schedule VII-3


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(millions of dollars)(unaudited)
  Three
months
  Six
months
 

Income (loss) attributable to equity holders of the Partnership for the three and six months ended June 30, 2010

    (4.5 )   8.4  
           

Fair value changes on natural gas supply and foreign exchange contracts

    20.3     25.2  

Higher operating margin at Curtis Palmer

    4.5     3.7  

Higher operating margin at the North Carolina plants

    2.7     2.9  

Higher income tax expense

    (8.4 )   (12.1 )

Strategic review and Transaction related costs

    (5.7 )   (5.7 )

Interest from Equistar and reversal of provision in 2010

    (3.9 )   (3.9 )

Lower operating margin at the BC Hydroelectric plants

    (1.8 )   (2.6 )

Lower operating margin at Northeast US natural gas plants

    (1.5 )   (1.0 )

Lower operating margin at the California plants

    (0.5 )   (1.8 )

Lower operating margin at the Northwest US plants

    (0.4 )   (1.9 )

Lower operating margin at the Ontario plants

    (0.2 )   (2.1 )

Other

    1.5     1.4  
           

Income attributable to equity holders of the Partnership for the three and six months ended June 30, 2011

    2.1     10.5  
           

        Income attributable to equity holders was $2.1 million or $0.04 per unit for the three months ended June 30, 2011 compared to a loss of $4.5 million or $0.08 per unit for the same period in 2010. In addition to the items described above for the change in funds from operations, the increase in income attributable to equity holders of $6.6 million was also the result of the following:

        Increases were partially offset by the following:

        Income attributable to equity holders was $10.5 million or $0.19 per unit for the six months ended June 30, 2011 compared to $8.4 million or $0.15 per unit for the same period in 2010. The $2.1 million increase in income attributable to equity holders for the six months ended June 30, 2011 compared to the same period in 2010 was primarily due to the items described above for the current quarter.


NON-IFRS MEASURES

        The Partnership uses operating margin as a performance measure, funds from operations and funds from operations per unit as cash flow measures and payout ratio as a distribution sustainability measure. These terms are not defined financial measures according to International Financial

Schedule VII-4


Table of Contents


Reporting Standards (IFRS) and do not have standardized meanings prescribed by IFRS. Therefore, these measures may not be comparable to similar measures presented by other enterprises. See Changes in Accounting Policies for a discussion on IFRS.

        The Partnership uses operating margin to measure the financial performance of plants and groups of plants. A reconciliation from operating margin to income before tax is as follows:

 
  Three months
ended
June 30
  Six months
ended
June 30
 
(millions of dollars) (unaudited)
  2011   2010   2011   2010  

Operating margin

    49.5     26.1     99.6     77.8  

Deduct:

                         
 

Depreciation

    22.5     24.5     45.5     47.9  
 

Administrative and other expenses

    9.6     1.6     13.8     5.6  
 

Finance costs

    10.6     10.0     21.5     21.4  
 

Finance income

        (1.8 )       (1.8 )
                   

Income (loss) before income tax

    6.8     (8.2 )   18.8     4.7  
                   

        The Partnership uses funds from operations as a measure of cash available to fund capital expenditures, debt repayments and distributions. This measure excludes working capital changes and includes interest and current tax expense recorded during the period, rather than interest and taxes paid, as these differences are expected to be largely reversed in future periods or represent reversals from prior periods. A reconciliation from funds from operations to cash provided by operating activities is as follows:

 
  Three months
ended
June 30
  Six months
ended
June 30
 
(millions of dollars) (unaudited)
  2011   2010   2011   2010  

Funds from operations

    26.8     30.3     53.7     67.2  

Adjustments:

                         
 

Current tax expense (recovery)

    (0.9 )   1.3     3.3     2.7  
 

Income taxes paid

    (3.1 )   (1.6 )   (3.1 )   (3.0 )
 

Interest expense

    9.6     9.7     19.4     19.3  
 

Interest income

        (1.8 )       (1.8 )
 

Interest paid

    (6.9 )   (6.1 )   (19.8 )   (19.3 )
 

Changes in operating working capital

    (2.5 )   (24.4 )   (0.9 )   (20.2 )
                   

Cash provided by operating activities

    23.0     7.4     52.6     44.9  
                   

        Funds from operations per unit is funds from operations divided by the weighted average number of units outstanding in the period.

        Payout ratio is defined as distributions divided by funds from operations less maintenance capital expenditures and excludes the after-tax costs of the strategic review and Transaction. Non-maintenance capital spending has been excluded from this measure as capital expenditures related to an expansion of the productive capacity of the business represent a long-term investment beyond the maintenance capital requirements of the existing business.

        The composition of the operating margin and payout ratio used in this interim MD&A is consistent with December 31, 2010 reporting. In the first quarter of 2011, the Partnership began using funds from operations and funds from operations per unit due to presentation changes in the statement of cash flows. Previously the Partnership used cash provided by operating activities and cash provided

Schedule VII-5


Table of Contents


by operating activities per unit which are equivalent to funds from operations and funds from operations per unit before working capital changes presented under previous Canadian generally accepted accounting principles (GAAP). Under GAAP, changes in operating working capital included timing differences between the recognition of interest and tax expense and payment of these expenses.


CHANGES IN ACCOUNTING POLICIES

International Financial Reporting Standards

        The Partnership's March 31, 2011 condensed interim consolidated financial statements were the Partnership's first condensed interim consolidated financial statements prepared in accordance with IAS 34—Interim Financial Reporting under IFRS and IFRS 1 First-time Adoption of International Financial Reporting Standards has been applied. For prior reporting periods up to and including the year ended December 31, 2010, the Partnership prepared its condensed interim consolidated financial statements in accordance with previous Canadian GAAP.

        The transition to IFRS did not have a significant impact on the key financial measures used by the Partnership. Both funds from operations and operating margin excluding fair value changes are the same under GAAP and IFRS. The Partnership's debt to total capitalization ratio increased to 54% at December 31, 2010 under IFRS from 53% under GAAP.

        The following tables provide reconciliations of equity and income attributable to equity holders of the Partnership reported under GAAP to those reported under IFRS.


Equity attributable to equity holders of the Partnership

(millions of dollars) (unaudited)
  As at
December 31,
2010
  As at
January 1,
2010
 

GAAP

    407.7     519.5  

Adjustments:

             
 

IAS 16 Property, plant and equipment

    (36.8 )   (36.8 )
 

IAS 37 Provisions

    (4.3 )   (7.1 )
 

IAS 36 Impairments

    (67.1 )   (23.7 )
 

IFRS 1 First time adoption of IFRS

    49.8     58.2  
 

IAS 39 Financial Instruments, Recognition and Measurement

    12.4     (4.9 )
 

Deferred taxes on the IFRS adjustments

    10.7     1.2  
 

Other impacts

    (2.8 )   1.1  
           

IFRS

    369.6     507.5  
           

Schedule VII-6


Table of Contents


Income attributable to equity holders of the Partnership

(millions of dollars) (unaudited)
  Three months
ended
June 30, 2010
  Six months
ended
June 30, 2010
  Twelve months
ended
December 31, 2010
 

GAAP

    (9.0 )   5.3     30.5  

Adjustments:

                   
 

IAS 36 Impairments

              (46.8 )
 

IAS 39 Financial Instruments, Recognition and Measurement

    (0.4 )   0.4     3.9  
 

Impact on depreciation and accretion of changes in carrying values

    1.6     1.3     (0.2 )
 

Deferred taxes on the IFRS adjustments

    3.3     1.4     14.3  
 

Other impacts

            (0.4 )
               

IFRS

    (4.5 )   8.4     1.3  
               


IAS 16 Property, plant and equipment (PP&E)

        IFRS are more specific with respect to the level at which component accounting is required. The appropriate components have been identified and the most significant difference from GAAP is that overhauls embedded within the initial carrying amount of a turbine must be treated as a separate component.


IAS 37 Provisions

        In accordance with IAS 37, provisions are required to be measured at the best estimate of the expected expenditure using discount rates appropriate for each liability. Under GAAP the provision was measured at fair value. The provision is to be re-measured at each reporting period for any changes in cash flow estimates, timing of decommissioning activity and discount rates. Accordingly, the Partnership re-measured its asset retirement obligations with revised discount rates for all decommissioning liabilities.


IAS 36 Impairments

        In accordance with IAS 36, the Partnership reviewed the recoverable amount for its cash generating units (CGUs) with allocated goodwill at both the date of transition to IFRS and in the third quarter of 2010. For these CGUs, management assessed whether there were any triggering events at December 31, 2010. The recoverable amounts were calculated on a fair value less cost to sell basis, using discounted cash flow models based on the Partnership's long term planning model. Previously under GAAP, the carrying values were compared to the undiscounted cash flows first and if the undiscounted cash flows exceeded carrying value then no further steps were taken. IAS 36 also requires that impairment testing be done on a CGU level and requires that goodwill be allocated to the CGU level and included in the impairment test for each CGU. The Partnership has determined its CGUs to be at the plant level.


IFRS 1 First time adoption of IFRS

        The Partnership took the IFRS 1 election to use fair value as deemed cost for the PP&E at certain plants at January 1, 2010.

        As a result of the Partnership taking the IFRS 1 election to deem the balance for the cumulative translation amount to be $nil on January 1, 2010, the accumulated other comprehensive loss decreased by $131.9 million. This election did not have a net impact on equity attributable to equity holders of the Partnership.

Schedule VII-7


Table of Contents


IAS 39 Financial instruments: recognition and measurement

        In accordance with IAS 39, Financial Instruments: Recognition and Measurement, financial assets available for sale must be measured at fair value. Previously under GAAP, an investment was carried at the lower of historic cost and fair value while the investment is carried at fair value under IFRS. Unrealized gains or losses in the fair value of the investment are recorded in other comprehensive income.

        In accordance with IAS 39, hedge effectiveness testing must incorporate the Partnerships' credit risk, which resulted in changes in the ineffective portion of the change in the fair value of the natural gas contracts.


REVENUES, OPERATING MARGIN(1) AND PLANT OUTPUT

 
  Three months ended June 30  
 
  2011   2010  
(millions of dollars except GWh) (unaudited)
  GWh   Revenues   Operating
Margin(1)
  GWh   Revenues   Operating
Margin(1)
 

Ontario plants

    247   $ 32.3   $ 6.4     295   $ 30.1   $ 6.6  

Williams Lake

    123     11.1     5.8     130     11.3     5.6  

BC hydroelectric plants

    75     4.8     3.5     102     6.4     5.3  

Northwest US plants

    105     13.3     8.0     162     14.3     8.4  

California plants

    232     24.3     8.7     206     23.3     9.2  

Curtis Palmer

    121     12.4     11.1     73     7.9     6.6  

Northeast US natural gas plants

    158     16.6     2.4     114     14.8     3.9  

North Carolina plants

    91     13.2     1.0     46     7.6     (1.7 )

PERC management fees

        0.8     0.4         0.8     0.4  
                           

    1,152     128.8     47.3     1,128     116.5     44.3  

Fair value changes

                                     
 

Foreign exchange contracts

        1.5     1.5         (19.2 )   (19.2 )
 

Natural gas supply contracts

            0.7             1.0  
                           

    1,152   $ 130.3   $ 49.5     1,128   $ 97.3   $ 26.1  
                           

 

 
  Six months ended June 30  
 
  2011   2010  
(millions of dollars except GWh) (unaudited)
  GWh   Revenues   Operating
Margin(1)
  GWh   Revenues   Operating
Margin(1)
 

Ontario plants

    583   $ 75.2   $ 23.8     668   $ 74.3   $ 25.9  

Williams Lake

    261     22.1     12.0     270     22.4     12.7  

BC hydroelectric plants

    119     8.4     5.7     161     10.5     8.3  

Northwest US plants

    169     27.1     16.0     303     29.2     17.9  

California plants

    468     42.1     10.7     456     46.9     12.5  

Curtis Palmer

    202     22.1     19.4     160     18.4     15.7  

Northeast US natural gas plants

    314     34.3     6.9     278     36.2     7.9  

North Carolina plants

    178     24.2     (0.7 )   101     15.7     (3.6 )

PERC management fees

        1.6     1.1         1.7     1.1  
                           

    2,294     257.1     94.9     2,397     255.3     98.4  

Fair value changes

                                     
 

Foreign exchange contracts

        4.4     4.4         (13.8 )   (13.8 )
 

Natural gas supply contracts

            0.3             (6.8 )
                           

    2,294   $ 261.5   $ 99.6     2,397   $ 241.5   $ 77.8  
                           

(1)
Operating margin is a non-IFRS financial measure. See Non-IFRS Measures.

Schedule VII-8


Table of Contents

 
  Three months ended
June 30
  Six months ended
June 30
 
Weighted average plant availability(1)
  2011   2010   2011   2010  

Ontario plants

    90 %   95 %   90 %   96 %

Williams Lake

    86 %   89 %   92 %   94 %

BC hydroelectric plants

    73 %   100 %   65 %   83 %

Northwest US plants

    84 %   85 %   91 %   91 %

California plants

    93 %   89 %   94 %   88 %

Curtis Palmer

    100 %   100 %   100 %   100 %

Northeast US natural gas plants

    90 %   94 %   88 %   97 %

North Carolina plants

    88 %   89 %   88 %   89 %
                   

Weighted average total

    88 %   90 %   90 %   92 %
                   

(1)
Plant availability represents the percentage of time in the period that the plant is available to generate power, whether actually running or not, and is reduced by planned and unplanned outages.

        Revenues excluding fair value changes in foreign exchange contracts were $128.8 million and $257.1 million for the three and six months ended June 30, 2011 compared to $116.5 million and $255.3 million for the same periods in 2010. The increase during the quarter was the result of higher generation at Curtis Palmer due to higher water flows and higher generation at the North Carolina plants. The increase during the six months ended June 30, 2011 was the result of higher generation at the Curtis Palmer and North Carolina plants partially offset by lower fuel recovery revenues at the California, Kenilworth and Morris plants in the first quarter caused by lower natural gas supply prices and lower generation, both of which result in a decrease in fuel costs.

        Operating margin excluding fair value changes in foreign exchange and natural gas supply contracts for the three and six months ended June 30, 2011 increased by $3.0 million and decreased by $3.5 million compared to the same periods in 2010. The increase during the quarter was the result of increased generation at the Curtis Palmer and North Carolina plants and insurance proceeds of $1.7 million at Calstock partially offset by higher natural gas transportation costs in Ontario and lower operating margin at the BC Hydroelectric and Morris plants. The decrease during the six months ended June 30, 2011 compared to the same period in 2010 was the result of lower margins at the Ontario, California, BC Hydroelectric and Northwest US plants, partially offset by higher margins at Curtis Palmer and North Carolina.

        Unrealized fair value changes in derivative instruments recorded for accounting purposes are not representative of their economic value when considering them in conjunction with the economically hedged item such as future natural gas purchases, future power sales or future US dollar cash flows.

Ontario Plants

        The Ontario plants reported operating margin of $6.4 million for the three months ended June 30, 2011 compared to $6.6 million for the same period in 2010. The decrease was primarily due to higher natural gas transportation costs partially offset by $1.7 million of insurance proceeds received at Calstock in the second quarter of 2011 and higher power pricing at Calstock. The PPA for Calstock was amended effective May 1, 2011 to increase the price for power delivered during peak power demand periods and to reduce the power the PPA counterparty is required to purchase during periods of low power demand. The amendment to the PPA is expected to result in an increase in the operating margin of Calstock of approximately $4 million to $5 million annually for the five year term. The Ontario plants reported operating margin of $23.8 million for the six months ended June 30, 2011 compared to $25.9 million for the same period in 2010. The decrease was due to the factors impacting the second

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quarter as well as a 70 day forced outage at Tunis due to a failure and the repair of the plant's steam turbine generator and higher wood waste costs at Calstock in the first quarter of 2011.

        Revenues from waste heat were $0.4 million and $4.8 million for the three and six months ended June 30, 2011 compared to $nil and $4.8 million for the same periods in 2010. Revenue from waste heat in the six months ended June 30, 2011 improved from levels experienced in the last nine months of 2010, which were $1.5 million, as a result of higher throughput on TransCanada Corporation's Canadian Mainline, the natural gas transmission line through Northern Ontario. Future throughput on the TransCanada Canadian Mainline will continue to be subject to supply and demand variances, however, the Partnership believes the decline in waste heat levelled off in 2010 as the economy has started a slow recovery. TransCanada's most recent projections of volumes for the next five years reflect a moderate increase in volumes in part attributable to TransCanada's plans to divert volumes from its Great Lakes Gas Transmission pipeline to the Canadian Mainline.

        Generation and availability at the Ontario plants were lower for the three and six months ended June 30, 2011 compared to the same periods in 2010 due to the outage at Tunis in 2011.

Williams Lake

        Operating margin from Williams Lake was $5.8 million and $12.0 million for the three and six months ended June 30, 2011 compared to $5.6 million and $12.7 million for the same periods in 2010. The decrease during the six months ended June 30, 2011 was due to the sale of more excess energy and less firm energy partially offset by higher excess energy prices in the current period. Excess energy prices, which are lower than firm energy prices, are $42 per megawatt hour (MWh) in 2011 compared to $35 per MWh in 2010. Excess and firm energy volumes for the full year 2011 are expected to be consistent with 2010.

BC Hydroelectric Plants

        Operating margin at the BC hydroelectric plants was $3.5 million and $5.7 million for the three and six months ended June 30, 2011 compared to $5.3 million and $8.3 million for the same periods in 2010. The decreases were primarily due to the replacement of the runner blades and rotor shaft in one of the Mamquam turbines in 2011 which resulted in lower availability and generation.

Northwest US Plants

        Operating margin from Frederickson was $2.9 million and $6.5 million for the three and six months ended June 30, 2011, a small decrease from $3.2 million and $7.0 million for the same periods in 2010.

        Operating margin from Manchief was $4.9 million for the three months ended June 30, 2011, a small decrease from $5.0 million for the same period in 2011. Operating margin was $9.1 million for the six months ended June 30, 2011 compared to $10.1 million for the same period in 2010. The decrease was primarily due to a property tax adjustment of $0.5 million in the first quarter of 2011.

        Operating margin from Greeley was $0.2 million and $0.4 million for the three and six months ended June 30, 2011 compared to $0.2 million and $0.8 million for the same periods in 2010. The decrease during the six month period was primarily due to turbine maintenance costs in the first quarter of 2011.

        Generation from the Northwest US plants was lower for the three and six months ended June 30, 2011 compared to the same periods in 2010 due to lower generation at Frederickson as a result of higher generation from hydroelectric facilities in the region in 2011.

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California Plants

        Operating margin from the Naval facilities was $7.4 million and $10.3 million for the three and six months ended June 30, 2011 compared to $8.3 million and $12.1 million for the same periods in 2010. The decreases were due to lower natural gas prices, which have a greater impact on revenue than cost of fuel, and maintenance at North Island.

        Operating margin from Oxnard was $1.3 million and $0.4 million for the three and six months ended June 30, 2011 compared to $0.9 million and $0.4 million for the same periods in 2010. The increase during the three months ended June 30, 2011 was due to an outage to complete a turbine replacement in 2010. For accounting purposes the Oxnard PPA with Southern California Edison Company (SCE) is considered a direct financing lease and a portion of the PPA payments received are considered principal repayments. During the three and six months ended June 30, 2011, $0.6 million and $1.1 million of PPA payments were applied against the long-term receivable from SCE compared to $0.4 million and $0.9 million for the same periods in 2010. Generation and availability at Oxnard were higher for the three and six months ended June 30, 2011 compared to the same periods in 2010 due to the turbine replacement project completed in 2010.

Curtis Palmer

        Operating margin from Curtis Palmer was $11.1 million and $19.4 million for the three and six months ended June 30, 2011 compared to $6.6 million and $15.7 million for the same periods in 2010. The increases were due to higher water flows.

Northeast US Natural Gas Plants

        Operating margin from Morris was $2.1 million and $5.5 million for the three and six months ended June 30, 2011 compared to $3.3 million and $6.3 million for the same periods in 2010. The decreases were due a 102 day forced outage of one of the plant's turbines, which also resulted in lower plant availability. The other natural gas turbines and boilers at Morris had sufficient capacity to meet the plant's power and steam commitments during the outage.

        Operating margin from Kenilworth was $0.3 million and $1.4 million for the three and six months ended June 30, 2011, small decreases from $0.6 million and $1.6 million for the same periods in 2010.

North Carolina Plants

        The North Carolina plants reported operating margin of $1.0 million and operating margin losses of $0.7 million for the three and six months ended June 30, 2011 compared to operating margin losses of $1.7 million and $3.6 million for the same periods in 2010. The increase in operating margin was due to the application of the terms of the interim and final PPAs and higher dispatch of the plants partially offset by turbine and boiler maintenance at Southport in the first quarter of 2011.

        In June 2011, the Partnership executed a 10 year PPA with Progress for the Partnership's two North Carolina facilities replacing the interim PPA that was effective April 1, 2011 under terms that were largely consistent with the interim PPA.

Fair value changes

        Unrealized gains on foreign exchange contracts were $1.5 million and $4.4 million for the three and six months ended June 30, 2011 compared to unrealized losses of $19.2 million and $13.8 million reported for the same periods in 2010. The changes in fair value were primarily due to changes in the forward prices for US dollars relative to Canadian dollars which decreased $0.006 and $0.030 for the three and six months ended June 30, 2011 compared to increases $0.057 and $0.033 for the same periods in 2010.

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        The Partnership recorded fair value gains on natural gas supply contracts of $0.7 million and $0.3 million for the three and six months ended June 30, 2011 compared to gains of $1.0 million and losses of $6.8 million for the same periods in 2010. The Partnership designated certain of its natural gas supply contracts as hedges. Net losses of $6.6 million and $0.4 million relating to these contracts were recorded in other comprehensive income in the three and six months ended June 30, 2011 compared to net gains of $4.4 million and net losses of $31.0 million for the same periods in 2010. The changes in the fair value of the natural gas contracts were primarily due to changes in natural gas forward prices. Alberta forward natural gas prices decreased $0.26 per gigajoule (GJ) and $0.14 per GJ for the three and six months ended June 30, 2011 compared to an increase of $0.10 per GJ and decrease $0.77 per GJ for the same periods in 2010.


COST OF FUEL

 
  Three months ended
June 30
  Six months ended
June 30
 
(millions of dollars)(unaudited)
  2011   2010   2011   2010  

Ontario plants

                         
 

Natural gas

    20.7     18.4     40.5     38.3  
 

Waste heat

    0.1     0.1     0.3     0.8  
 

Wood waste

    0.9     1.1     2.3     1.5  
                   

    21.7     19.6     43.1     40.6  

Williams Lake—wood waste

    2.0     2.3     4.7     4.1  

Northwest US plants—natural gas

    2.4     2.6     4.9     5.2  

California plants—natural gas

    10.9     9.8     21.9     25.6  

Northeast US natural gas plants

    10.7     8.6     21.7     23.8  

North Carolina plants—wood waste, tire-derived fuel & coal

    6.2     5.1     13.5     10.8  
                   

    53.9     48.0     109.8     110.1  

Fair value changes on natural gas contracts

    (0.7 )   (1.0 )   (0.3 )   6.8  
                   

    53.2     47.0     109.5     116.9  
                   

        Fuel costs, which are the Partnership's most significant cost of operations, include commodity costs, transportation costs and fair value changes on natural gas supply contracts.

        For the three and six months ended June 30, 2011, fuel costs, excluding fair value changes on natural gas contracts, were $53.9 million and $109.8 million compared to $48.0 million and $110.1 million for the same periods in 2010.

        Fuel costs at the Ontario plants for the three and six months ended June 30, 2011 were $21.7 million and $43.1 million compared to $19.6 million and $40.6 million for the same periods in 2010. The increase during the three months ended June 30, 2011 was primarily due to higher natural gas transportation costs. The increase during the six months ended June 30, 2011 was primarily due to higher natural gas transportation costs and higher wood waste costs earlier in 2011 partially offset by lower waste heat costs in the first quarter of 2011.

        Williams Lake incurred fuel costs of $2.0 million for the three months ended June 30, 2011, a small decrease from $2.3 million for the same period in 2010. Fuel costs were $4.7 million for the six months ended June 30, 2011 compared to $4.1 million for the same period in 2010. The increase was due to higher prices for waste wood and higher fuel consumption in the first quarter of 2011.

        The Northwest US plants incurred fuel costs of $2.4 million and $4.9 million for the three and six months ended June 30, 2011, a small decrease from $2.6 million and $5.2 million for the same periods in 2010.

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        Fuel costs at the California facilities were $10.9 million and $21.9 million for the three and six months ended June 30, 2011 compared to $9.8 million and $25.6 million for the same periods in 2010. The increase during the quarter was primarily due to higher generation in 2011. The decrease during the six month period was primarily due to lower natural gas prices earlier in the year in 2011.

        The Northeast US natural gas plants incurred fuel costs of $10.7 million and $21.7 million for the three and six months ended June 30, 2011, compared to $8.6 million and $23.8 million for the same periods in 2010. The increase during the quarter was primarily due to higher generation in 2011. The decrease during the six month period was primarily due to lower natural gas prices earlier in the year in 2011.

        The North Carolina plants incurred fuel costs of $6.2 million and $13.5 million for the three and six months ended June 30, 2011 compared to $5.1 million and $10.8 million for the same periods in 2010. The increase was the result of increased generation at the plants.

        The Curtis Palmer, Mamquam and Moresby Lake hydroelectric plants do not have fuel costs.


OPERATING AND MAINTENANCE EXPENSE

 
  Three months ended
June 30
  Six months ended
June 30
 
(millions of dollars)(unaudited)
  2011   2010   2011   2010  

Ontario plants

    4.2     3.9     8.3     7.8  

Williams Lake

    3.3     3.4     5.4     5.6  

BC hydroelectric plants

    1.3     1.1     2.7     2.2  

Northwest US plants

    2.9     3.3     6.2     6.1  

California plants

    4.7     4.3     9.5     8.8  

Curtis Palmer

    1.3     1.3     2.7     2.7  

Northeast US natural gas plants

    3.5     2.3     5.7     4.5  

North Carolina plants

    6.0     4.2     11.4     8.5  

PERC management expenses

    0.4     0.4     0.5     0.6  
                   

    27.6     24.2     52.4     46.8  
                   

        Operating and maintenance expenses include payments to the Manager and third parties for the operation and routine maintenance of the plants. Fees paid to the Manager are based on fixed charges adjusted annually for inflation for the Canadian plants, Curtis Palmer and Manchief, and a flow through of costs for the remaining US plants. Operating and maintenance expenses were $27.6 million and $52.4 million for the three and six months ended June 30, 2011 compared to $24.2 million and $46.8 million for the same periods in 2010. The increases were due to repairs and maintenance at Morris, Southport and Roxboro and a $0.5 million property tax adjustment at Manchief.


DEPRECIATION

        Depreciation expense for the three and six months ended June 30, 2011 was $22.5 million and $45.5 million, a small decrease from $24.5 million and $47.9 million for the same periods in 2010.


ADMINISTRATIVE AND OTHER EXPENSES

        Administrative and other expenses, which include fees payable to CPC and general and administrative costs, were $9.6 million and $13.8 million for the three and six months ended June 30, 2011 compared to $1.6 million and $5.6 million for the same periods in 2010. The increases were due to costs associated with the strategic review and the Transaction of $5.7 million incurred during the

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second quarter of 2011 (See Significant Events—Atlantic Power Corporation agrees to acquire Capital Power Income L.P.) and the reversal of an allowance for doubtful accounts in 2010.


FINANCE COSTS

 
  Three months ended
June 30
  Six months ended
June 30
 
(millions of dollars)(unaudited)
  2011   2010   2011   2010  

Interest on long-term debt

    9.5     9.7     19.1     19.3  

Foreign exchange losses

        (0.5 )       0.2  

Accretion and amortization

    0.7     0.6     1.2     1.3  

Other

    0.4     0.2     1.2     0.6  
                   

    10.6     10.0     21.5     21.4  
                   

        Finance costs were $10.6 million and $21.5 million for the three and six months ended June 30, 2011, small increases from $10.0 million and $21.4 million for same periods in 2010.


FINANCE INCOME

        Finance income in the three and six months ended June 30, 2010 represents interest earned on a receivable from Equistar while they underwent Chapter 11 proceedings.


INCOME TAX EXPENSE (RECOVERY)

        Income tax expense was $1.1 million and $1.2 million for the three and six months ended June 30, 2011 compared to recoveries of $7.3 million and $10.9 million for the same periods in 2010. Tax expense increased as the taxable income of the Partnership was taxed at the Partnership level in 2011 rather than in the hands of unitholders as was the case for periods prior to 2011 due to changes to the SIFT legislation that became effective January 1, 2011. Additionally, income taxes are recorded in the preferred share dividend of a subsidiary company category. The following table summarizes income taxes by category.

 
  Three months ended
June 30, 2011
  Six months ended
June 30, 2011
 
(millions of dollars)(unaudited)
Financial statement category
  Current   Deferred   Total   Current   Deferred   Total  

Income tax expense (recovery)

    (2.2 )   3.3     1.1     0.7     0.5     1.2  

Preferred share dividends of a subsidiary company

    1.3     (0.8 )   0.5     2.6     (1.9 )   0.7  
                           

    (0.9 )   2.5     1.6     3.3     (1.4 )   1.9  
                           

 

 
  Three months ended
June 30, 2010
  Six months ended
June 30, 2010
 
(millions of dollars)(unaudited)
Financial statement category
  Current   Deferred   Total   Current   Deferred   Total  

Income tax expense (recovery)

        (7.3 )   (7.3 )   0.1     (11.0 )   (10.9 )

Preferred share dividends of a subsidiary company

    1.3     (0.7 )   0.6     2.6     (1.7 )   0.9  
                           

    1.3     (8.0 )   (6.7 )   2.7     (12.7 )   (10.0 )
                           


PREFERRED SHARE DIVIDENDS OF A SUBSIDIARY COMPANY

        A subsidiary of the Partnership issued preferred shares, which paid dividends net of tax of $3.6 million and $7.1 million for the three and six months ended June 30, 2011, compared to $3.6 million and $7.2 million for the same periods in 2010. Part VI.1 tax is paid at a rate of 40% of the dividends and a deduction from Part I tax is available for payment of Part VI.1 tax.

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LIQUIDITY AND CAPITAL RESOURCES

Distributions

        When cash provided by operating activities exceeds distributions and maintenance capital expenditures, the Partnership utilizes the difference to stabilize future distributions, to finance growth capital expenditures and to make debt repayments. When cash provided by operating activities is less than distributions and maintenance capital expenditures, the Partnership utilizes available cash balances and short-term financing to cover the shortfall.

        The Partnership terminated its Premium Distribution and Distribution Reinvestment Plan on June 30, 2011.

 
  Three months ended
June 30
  Six months ended
June 30
 
(millions of dollars)(unaudited)
  2011   2010   2011   2010  

Distributions

    24.8     24.2     49.5     48.1  

Cash provided by operating activities

    23.0     7.4     52.6     44.9  

Income (loss) attributable to equity holders of the Partnership

    2.1     (4.5 )   10.5     8.4  

Payout ratio(1)

    100 %   100 %   107 %   80 %

Additions to property, plant and equipment

    6.1     8.2     13.3     12.8  

(Shortfall) excess of cash provided by operating activities over distributions

    (1.8 )   (16.8 )   3.1     (3.2 )

Shortfall of income attributable to equity holders of the Partnership over distributions

    (22.7 )   (28.7 )   (39.0 )   (39.7 )

(1)
Payout ratio is distributions divided by funds from operations less maintenance capital expenditures. See Non-IFRS Measures. The after-tax costs of the strategic review and Transaction are not included.

        Distributions exceeded cash provided by operating activities by $1.8 million for the three months ended June 30, 2011 and cash provided by operating activities exceeded distributions by $3.1 million for the six months ended June 30, 2011. The Partnership also incurred capital expenditures of $6.1 million and $13.3 million during the three and six months ended June 30, 2011, which the Partnership financed with cash provided by operating activities, available cash balances and proceeds from its dividend reinvestment plans.

        The payout ratio exceeded 100% in the six months of 2011. The Partnership evaluates the payout ratio on an annual basis as quarterly results can be affected by the timing of cash flow items such as maintenance capital expenditures. The Partnership expects the payout ratio for 2011 to be less than 100%. The after-tax costs associated with the strategic review and sale to Atlantic Power are not included in the determination of the payout ratio as they do not represent requirements of the existing business.

        Income attributable to equity holders of the Partnership is not necessarily comparable to distributions as income includes items such as changes in the fair value of derivative instruments. Aside from these items, management expects that distributions will exceed income attributable to equity holders of the Partnership. Accordingly, a portion of the distributions represent a return of capital. To date, and subject to ensuring adequate liquidity, the Partnership has chosen to make distributions that include a return of capital.

        To the extent there is a shortfall between the Partnership's cash provided by operating activities and distributions and capital expenditures, the Partnership has available to it two revolving credit facilities, each of $100.0 million expiring in September 2012 and October 2012 and a third revolving credit facility of $125.0 million expiring in June 2013. The Partnership also has two demand facilities of

Schedule VII-15


Table of Contents


$20.0 million and US$20.0 million respectively. Alternatively, in the case of major investments of capital, the Partnership may obtain new capital from external markets at the time of the required investment, utilizing its $600 million shelf prospectus which expires in August 2012.


Capital expenditures

        Capital expenditures for the three and six months ended June 30, 2011 totalled $6.1 million and $13.3 million respectively compared to $8.2 million and $12.8 million for the same periods in 2010. Capital spending included spending for the enhancement of the North Carolina plants.

 
  Three months ended
June 30
  Six months ended
June 30
 
(millions of dollars)(unaudited)
  2011   2010   2011   2010  

Maintenance capital expenditures

    6.1     6.0     11.6     7.4  

North Carolina enhancement project

        2.2     1.7     5.4  
                   

    6.1     8.2     13.3     12.8  
                   

        The Partnership substantially completed the final testing of the enhancements to the North Carolina plants in the first quarter of 2011 and plans to invest an additional $3 million in the remaining six months of 2011.


Financing

        The following table summarizes the long-term debt of the Partnership.

(millions of dollars)(unaudited)
  June 30
2011
  December 31
2010
 

Senior unsecured notes, due 2036

    210.0     210.0  

Senior unsecured notes (US$415.0) due 2014 to 2019

    400.3     412.8  

Revolving credit facilities

    69.5     86.1  
           

    679.8     708.9  
           

        The Partnership's debt to total capitalization ratio as at June 30, 2011 was 55%, a small increase from 54% at December 31, 2010. The debt to total capitalization ratio is calculated as follows:

Debt to total capitalization ratio =   Debt (short-term debt + long-term debt)

Debt + preferred shares + partners' equity

        Under the terms of its debt agreements, the Partnership must maintain a debt to capitalization ratio of not more than 65% at the end of each fiscal quarter. Under the revolving credit facilities, in the event the Partnership is assigned both a rating of less than BBB+ by Standard and Poors (S&P) and a rating of less than BBB(high) by DBRS Limited (DBRS), the Partnership also would be required to maintain a ratio of EBITDA (earnings before interest, income taxes, depreciation and amortization as defined in the credit facilities) to interest expense of not less than 2.5 to 1, measured quarterly. Although the Partnership is not required to meet the EBITDA to interest ratio, the ratio was 3.8 to 1 as at June 30, 2011.

        S&P has assigned the Partnership a credit rating of BBB (stable). S&P placed the debt rating on credit watch with negative implications at the time of the announcement of Atlantic Power's acquisition of the Partnership. DBRS has assigned the Partnership a BBB(high) debt rating. DBRS placed the debt rating under review with negative implications at the time of the announcement of the strategic review process.

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Table of Contents

        The BBB debt rating by S&P is the fourth highest rating out of 10 rating categories. According to S&P, an obligor rated BBB has adequate capacity to meet its financial commitments. The BBB rating is DBRS' fourth highest of 10 categories. DBRS' BBB(high) rating designates the Partnership's debt as being of satisfactory credit quality with the protection of interest and principal still substantial. The high classification shows the relative standing within the major rating categories. The review with negative implications by DBRS and the credit watch with negative implications by S&P highlight the potential that the long-term ratings may be lowered.

        Having an investment grade credit rating improves the Partnership's ability to re-finance existing debt as it matures and to access cost competitive capital for future growth.


Financial market liquidity

        The exposure of the Partnership to the ongoing volatility in the Canadian and US financial markets is substantially unchanged from December 31, 2010. For further information on the Partnership's outlook, refer to the Partnership's December 31, 2010 MD&A. The Partnership has a sufficient liquidity position with revolving credit facilities of $325 million of which $255.5 million was available at June 30, 2011. The Partnership also has a demand credit facility of $20.0 million with Canadian tier 1 banks and a second demand credit facility of US$20.0 million with a US tier 1 bank. Principal repayments on the Partnership's long-term debt facilities are as follows:

Year
  Principal repayment
(unaudited) (millions of dollars)
 

2012

    69.5  

2014

    183.3  

2017

    144.7  

2019

    72.3  

2036

    210.0  

        Uncertainty in global financial markets and, in particular, the Canadian and US financial markets may adversely affect the Partnership's ability to arrange permanent long-term financing for acquisitions, for significant capital expenditures and potentially to refinance indebtedness under the credit facilities outstanding at their maturity dates. This may also affect the Partnership's credit ratings.


FOREIGN EXCHANGE RISK MANAGEMENT

        The Partnership manages the foreign exchange risk of its anticipated US dollar-denominated cash flows from its US plants through the use of forward foreign exchange contracts for periods up to seven years. As at June 30, 2011, US$297.3 million of expected future US cash flows were economically hedged for 2011 to 2016 at a weighted average exchange rate of $1.12 to US$1.00.

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Table of Contents


TRANSACTIONS WITH RELATED PARTIES

 
  Three months ended
June 30
  Six months ended
June 30
 
(millions of dollars)(unaudited)
  2011   2010   2011   2010  

Transactions with CPC

                         

Cost of fuel—Greeley natural gas contract

   
0.3
   
0.2
   
0.7
   
0.3
 

Operating and maintenance expense

   
12.1
   
11.3
   
24.3
   
23.5
 

Administrative and other expenses

                         
 

Base fee

    0.3     0.3     0.5     0.5  
 

Enhancement fee

                0.2  
 

General and administrative costs

    2.3     1.1     4.8     3.4  
                   

    2.6     1.4     5.3     4.1  
                   

        In operating the Partnership's 20 power plants, the Partnership and CPC engage in a number of related party transactions which are in the normal course of business. These transactions are based on contracts and many of the fees are escalated by inflation. The table above summarizes the amounts included in the calculation of income for the three and six months ended June 30, 2011 and 2010.

        During the three and six months ended June 30, 2011, the Partnership made cash distributions to CPC in the amount proportionate to its ownership interest. At June 30, 2011, CPC owned 29.2% of the Partnership's units (30.0% at June 30, 2010).

        The Partnership has entered into an agreement to sell the North Carolina plants to CPC for $121 million concurrent with and contingent upon the completion of the Transaction. The independent directors of the Board relied partially on a fairness opinion provided by CIBC World Markets Inc. as part of the approval of this agreement. Additionally, concurrent with and contingent upon the completion of the Transaction, the Partnership has entered into an agreement to terminate certain management and operations agreements with the Manager for a termination payment of $8.5 million.


CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES

        There were no material changes to the Partnership's purchase obligations, commitments or contingencies during the six months ended June 30, 2011, including payments for the next five years and thereafter, other than described below. For further information on these obligations, refer to the Partnership's December 31, 2010 MD&A.

        If the Transaction with Atlantic Power fails to receive unitholder approval, the Partnership will reimburse Atlantic Power for its costs associated with the Transaction up to $8 million. Further, any solicitation or recommendation of a competing proposal or offer will result in the payment of a $35 million termination fee. There is no possibility of any reimbursement of these amounts once paid.

        Concurrent with and contingent upon the completion of the Transaction, the Partnership will pay $8.5 million to CPC for the termination of certain management and operations agreements and will pay success fees of approximately $12 million to its financial advisors.


CRITICAL ACCOUNTING ESTIMATES AND POLICIES

        Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the Partnership's consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. The Partnership's critical accounting estimates include tax provision calculations, depreciation expense, asset retirement

Schedule VII-18


Table of Contents


obligations and fair value estimates. The following are the Partnership's most significant accounting policies and the items for which critical estimates were made in the financial statements and should be read in conjunction with the notes to the unaudited condensed interim consolidated financial statements.


Useful lives of assets

        The useful lives of the Partnership's property, plant and equipment and intangible assets are estimated for purposes of determining depreciation expense, in determining asset retirement obligations and in testing for potential impairment of long-lived assets. The estimated useful lives of assets are determined based on judgment, current facts, past experience, designed physical life, potential technological obsolescence and contract periods.

        The Partnership depreciates its property, plant, equipment and intangible assets over their estimated useful lives. The Partnership depreciates its power generation plant and equipment, less estimated residual value, on a straight-line basis over their estimated remaining useful lives. Other equipment is capitalized and amortized over estimated service lives. Intangible assets are depreciated on a straight line basis over their remaining lives.


Fair values

        Fair values are estimated to measure asset retirement obligations, to measure impairment, if any, of long-lived assets and goodwill, to determine purchase price allocations and to value derivative instruments.

        Expected demolition, restoration and other related costs to settle the Partnership's asset retirement obligations are estimated and discounted to determine the fair value of the asset retirement obligations.

        Items of property, plant and equipment and intangible assets are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount exceeds its recoverable amount. The recoverable amount is the higher of its fair value less costs to sell and its value in use. The value in use of an asset is the present value of estimated future cash flows using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. The fair value less costs to sell is based on estimated market values based on actual market transactions, if available, or a valuation model is used.

        For determining purchase price allocations for business combinations, the Partnership is required to estimate the fair value of certain assets and liabilities. For the purpose of impairment testing, goodwill acquired in an acquisition is, from the date of acquisition, allocated to each of the Partnership's CGU that are expected to benefit from the acquisition. Goodwill is tested for impairment annually at the CGU level by comparing the recoverable amount of the CGU to which the goodwill relates to the carrying amount, including goodwill, of the CGU. The recoverable amount of the CGU is considered to be the higher of its value in use and its fair value less cost to sell. In assessing value in use, the estimated future cash flows are discounted using a discount rate that reflects current market assessments of the time value of money and the risks specific to each unit.

        Estimates of fair value for decommissioning liabilities, purchase price allocations, long-lived asset and goodwill impairment testing are based on discounted cash flow techniques employing management's best estimates of future cash flows based on specific assumptions and using an appropriate discount rate.

        Fair values of derivative instruments including foreign exchange contracts and natural gas supply contracts are based on quoted market prices. Changes in fair values are recorded in revenue and cost of fuel in the income statement, in other comprehensive income and in derivative instruments asset/liability on the balance sheet.

Schedule VII-19


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INTERNAL CONTROL OVER FINANCIAL REPORTING

        During the period, the Partnership transitioned to IFRS. However there were no significant changes to the Partnership's policies and internal controls. Accordingly, there were no changes made to the Partnership's internal controls over financial reporting during the interim period ended June 30, 2011 that have materially affected or are reasonably likely to materially affect internal control over financial reporting.


BUSINESS RISKS

        The Partnership's business and operational risks remain substantially unchanged since December 31, 2010 as provided in the Partnership's December 31, 2010 MD&A. Recent developments in business and operational risks are described below. For further information on business risks, refer to the Partnership's December 31, 2010 MD&A.


Failure to complete the Transaction could negatively impact the unit price and the future business and financial results of the Partnership

        If the Transaction is not completed, the ongoing business of the Partnership may be adversely affected. If the Transaction is not completed, the Partnership will have to consider alternative transactions, including the internalization of management. Additionally, if the Transaction is not completed and the arrangement agreement with Atlantic Power is terminated, the Partnership may be required to pay a break-up fee in the amount of $35.0 million. The foregoing risks, or other risks arising in connection with the failure of the Transaction, including the diversion of management attention from conducting the business of the Partnership and pursuing other opportunities while the Transaction is pending, may have an adverse effect on the business, operations, financial results and unit price of the Partnership.


The arrangement agreement with Atlantic contains provisions that could discourage a potential competing acquirer of the Partnership

        The arrangement agreement with Atlantic contains "no shop" provisions that, subject to limited exceptions, restrict the Partnership's and the General Partner's ability to solicit, encourage, facilitate or discuss competing third-party proposals to acquire units or assets of the Partnership. In certain specified circumstances, one of the parties will be required to pay a break-up fee of $35.0 million to the other party. These provisions could discourage a potential competing acquirer that might have an interest in acquiring all or a significant part of the Partnership from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share or unit cash or market value than the market value proposed to be received or realized in the Transaction, or might result in a potential competing acquirer proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the $35.0 million termination fee that may become payable in certain circumstances.


In certain circumstances, if the arrangement agreement with Atlantic Power is terminated without any payment of a termination payment, the Partnership may be required to make an expense reimbursement payment to Atlantic Power

        Under the arrangement agreement with Atlantic Power, the Partnership would be required to make an expense reimbursement payment to Atlantic Power, up to a maximum of $8.0 million, in the event the agreement is terminated in certain circumstances, including, but not limited to, if the Partnership unitholders do not approve the Transaction. If the Transaction is not completed and the Partnership determines to seek another business combination, it may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the Transaction.

Schedule VII-20


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FUTURE ACCOUNTING STANDARDS

        A number of new standards, and amendments to standards and interpretations, are not yet effective for the quarter ended June 30, 2011 and have not been applied in preparing the unaudited condensed interim consolidated financial statements. The following standards and interpretations have been issued by the International Accounting Standards Board and the International Financial Reporting Interpretations Committees with effective dates relating to the annual periods starting on or after the effective dates as follows:

International Accounting Standards (IAS/IFRS)
  Effective Date  
IFRS 9—Financial Instruments     January 1, 2013  

IAS 12—Income Taxes

 

 

January 1, 2012

 

IFRS 10—Consolidated Financial Statements

 

 

January 1, 2013

 

IFRS 11—Joint Arrangements

 

 

January 1, 2013

 

IFRS 12—Disclosures of Interests in Other Entities

 

 

January 1, 2013

 

IFRS 13—Fair Value Measurement

 

 

January 1, 2013

 

IAS 1—Presentation of Financial Statements

 

 

July 1, 2012

 

        IFRS 9 applies to the classification and measurement of financial assets and financial liabilities. It is the first of three phases of a project to develop standards to replace IAS 39—Financial Instruments and was initiated in response to the crisis in financial markets.

        The amendments to IAS 12 relate to the measurement of deferred taxes for investment property, PP&E and intangible assets carried at fair value.

        IFRS 10 replaces IAS 27 Consolidated and Separate Financial Statements and SIC—12 Consolidation—Special Purpose Entities. IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements. It provides a single consolidation model that identifies control as the basis for consolidation for all types of entities. IFRS 12 provides comprehensive disclosure requirements for all forms of interests in other entities, including subsidiaries, joint arrangements, associates and special purpose vehicles.

        IFRS 11 supersedes IAS 31—Interests in Joint Ventures and SIC 13—Jointly Controlled Entities—Non-Monetary Contributions by Venturers. The standard requires a single method to account for interests in jointly controlled entities. All joint ventures are required to be recognized as an investment and be accounted for on an equity basis.

        IFRS 13 defines fair value, sets out in a single IFRS a framework for measuring fair value and requires disclosures about fair value measurements. IFRS 13 applies when other IFRSs require or permit fair value measurements. It does not introduce any new requirements to measure an asset or a liability at fair value, change what is measured at fair value in IFRSs or address how to present changes in fair value.

        The amendments to IAS 1 provide improvements to the presentation of components of other comprehensive income. It requires entities to group items within other comprehensive income that may be reclassified to profit or loss.

        The extent of the impact of adoption of these standards and interpretations on the consolidated financial statements of the Partnership has not been determined.

Schedule VII-21


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OUTLOOK

        The Partnership's financial expectations for 2011 are moderately lower than its previous 2011 financial guidance provided in the Partnership's December 31, 2010 MD&A issued in March 2011. The 2011 financial guidance provided in the December 31, 2010 MD&A was based on the expectation that funds from operations would be higher in 2011 compared to 2010. The Partnership now expects funds from operations in 2011 to be consistent with 2010, excluding costs associated with the strategic review and the Transaction. The revised expectations primarily reflect lower expected operating margins at Southport and Roxboro as a result of lower expectations for retroactive payments for the period prior to entering into the interim PPA with Progress and lower expectations for ancillary services at Morris, which were previously expected to be higher in 2011 compared to 2010.

        On June 20, 2011, the Partnership and Atlantic Power jointly announced that they had entered into an arrangement agreement to which Atlantic Power would acquire, directly and indirectly, all of the outstanding limited partnership units of the Partnership for $19.40 per limited partnership unit (See Significant Events—Atlantic Power Corporation agrees to acquire Capital Power Income L.P.). The Partnership intends to continue paying its monthly distribution, equal to $1.76 per limited partnership unit on an annual basis, through the month preceding the month of closing of the Transaction with Atlantic Power. The Transaction is expected to be completed in the fourth quarter of 2011, subject to customary approvals including unitholder and shareholder approvals. The Transaction is a result of the strategic review process undertaken by the Partnership that was publicly announced on October 5, 2010. The strategic review process was undertaken by a special committee of independent directors of the General Partner in co-operation with CPC and included an evaluation of a broad range of alternatives for the Partnership.

        In June 2011, the Partnership executed a 10 year PPA with Progress for the Partnership's two North Carolina facilities replacing the interim PPA that was effective April 1, 2011 under terms that were largely consistent with the interim PPA. Operating margin for the plants is expected to average US$15 million per year during the 10 year terms of the final PPAs, with higher earnings expected in earlier years. The Partnership has agreed to sell Southport and Roxboro to an affiliate of CPC for $121 million (See Significant Events—Atlantic Power Corporation agrees to acquire Capital Power Income L.P.).


SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA

 
  2011   2010   2009(2)  
(unaudited)
(millions of dollars except per unit amounts)
  Second   First   Fourth   Third   Second   First   Fourth   Third  

Revenues

    130.3     131.2     150.2     140.7     97.3     144.2     138.2     155.5  

Operating margin(1)

    49.5     50.1     55.6     58.0     26.1     51.7     58.9     65.9  

Income (loss) attributable to equity holders of the Partnership

    2.1     8.4     19.7     (26.8 )   (4.5 )   12.9     17.4     30.7  

Funds from operations(1)

    26.8     26.8     25.9     32.0     30.3     36.9     35.3     37.3  

Capital expenditures

    6.1     7.2     6.8     8.7     8.2     4.6     24.8     33.0  

Distributions

    24.8     24.7     24.5     24.3     24.2     23.9     23.8     23.7  

Per unit statistics

                                                 

Income (loss) attributable to equity holders of the Partnership

  $ 0.04   $ 0.15   $ 0.35   $ (0.49 ) $ (0.08 ) $ 0.24   $ 0.32   $ 0.57  

Funds from operations(1)

  $ 0.48   $ 0.48   $ 0.47   $ 0.58   $ 0.55   $ 0.68   $ 0.65   $ 0.69  

Distributions

  $ 0.44   $ 0.44   $ 0.44   $ 0.44   $ 0.44   $ 0.44   $ 0.44   $ 0.44  

(1)
The selected quarterly consolidated financial data has been prepared in accordance with IFRS except for operating margin, funds from operations and funds from operations per unit. See Non-IFRS Measures.

(2)
Results for 2009 have been prepared using previous Canadian GAAP not IFRS.

Schedule VII-22


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Factors impacting quarterly financial results

        The Partnership's Selected Quarterly Consolidated Financial Data, which has been prepared in accordance with IFRS, except as noted, is set out above. Quarterly revenues, income and funds from operations are affected by seasonal contract pricing, seasonal weather conditions, fluctuations in US dollar exchange rates relative to the Canadian dollar, attainment of firm energy requirements, natural gas prices, waste heat availability and planned and unplanned plant outages, as well as items outside of the normal course of operations. Quarterly income is also affected by fair value changes in foreign exchange contracts and natural gas supply contracts.

        The Partnership's cash flow tends to be relatively stable over the year with seasonal fluctuations at the individual facilities. The Naval facilities earn approximately 75% of their capacity revenue during the summer peak demand months and all the California plants can earn performance bonuses during these months. Under the power sales contracts for the Ontario plants, the Partnership receives higher per megawatt hour prices in the winter months (October to March) and lower prices in the summer months (April to September). The lower summer prices reduce the threshold for economic curtailments thereby increasing the profitability of enhancements, natural gas prices being equal. Contributions from Williams Lake are usually lower in the fourth quarter once the annual firm energy requirements are fulfilled and the plant is only producing lower-priced excess energy. Revenues from the hydroelectric facilities are generally higher in the spring months due to seasonally higher water flows.

        Significant items which impacted the last eight quarters' income were as follows:

        The Partnership recorded gains on the change in the fair value of the natural gas supply contracts in the fourth quarter of 2009 and the second quarters of 2010 and 2011. Losses were recorded in the third quarter of 2009, the first, third and fourth quarters of 2010 and the first quarter of 2011.

        Unrealized fair value changes on foreign exchange contracts resulted in gains in the third and fourth quarters of 2009, the first, third and fourth quarters of 2010 and the first and second quarters of 2011. Losses were recorded in the second quarter of 2010.

        In the third quarter of 2010, the Partnership recorded a $46.8 million asset impairment charge related to the Tunis and Calstock plants.

        Prior to January 1, 2011, the taxable income of the Partnership was taxed in the hands of unitholders and was taxed at the Partnership level thereafter.


FORWARD-LOOKING INFORMATION

        Certain information in this MD&A is forward-looking and related to anticipated financial performance, events and strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target" and "expect" or similar words suggest future outcomes. By their nature, such statements are subject to significant risks, assumptions and uncertainties, which could cause the Partnership's actual results and experience to be materially different than the anticipated results. In particular, forward-looking information and statements include: (i) expectations that the Partnership will continue to pay the same amount of distributions through the month preceding the month that the Transaction with Atlantic Power closes, (ii) the closing and the timing of the closing of the Transaction with Atlantic Power in the fourth quarter of 2011, (iii) the sale of the Roxboro and Southport plants to an affiliate of CPC, (iv) that differences between interest and current tax expense recorded and interest and taxes paid will be largely reversed in future periods or represent reversals from prior periods, (v) expectations regarding any increase in the operating margin of Calstock as a consequence of the amended PPA, (vi) expectations regarding waste heat and throughput on the TransCanada Canadian Mainline, (vii) the recovery of the economy, (viii) expectations regarding excess and firm energy volumes for 2011, (ix) expectations regarding the Partnership's payout ratio for 2011, (x) expectations that distributions will exceed income attributable to the Partnership's unit holders,

Schedule VII-23


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(xi) expectations regarding the Partnership's ability to obtain new capital from external markets pursuant to its existing shelf prospectus, (xii) plans to invest an additional $3 million in 2011 with respect to capital expenditures at the North Carolina plants, (xiii) expectations regarding the Partnership's funds from operations in 2011, (xiv) expectations regarding retroactive payments for Southport and Roxboro and the expected operating margin and earnings from these facilities under the final PPA's, and (xv) expectations regarding ancillary services at the Morris facility.

        These statements are based on certain assumptions and analysis made by the Partnership in light of its experience and perception of historical trends, current conditions and expected future developments and other factors it believes are appropriate. The material factors and assumptions used to develop these forward-looking statements include, but are not limited to: (i) the Partnership's operations, financial position, available credit facilities and access to capital markets, (ii) the Partnership's assessment of commodity, currency and power markets, (iii) the markets and regulatory environment in which the Partnership's facilities operate, (iv) the state of capital markets, the Partnership's credit rating and the availability and cost of financing, (v) management's analysis of applicable tax legislation, (vi) the assumption that the currently applicable and proposed tax laws will not change and will be implemented, (vii) the assumption that counterparties to fuel supply, power purchase and other agreements will continue to perform their obligations under the agreements, (viii) that current expectations regarding throughput on the TransCanada Canadian Mainline will continue, (ix) the level of plant availability and dispatch, (x) the performance of contractors and suppliers, (xi) the renewal or replacement and terms of PPAs, (xii) the ability of the Partnership to successfully realize the benefits of its capital projects, (xiii) the ability of the Partnership to implement its strategic initiatives and whether such initiatives will yield the expected benefits, (xiv) expected water flows, (xv) the ability of the Partnership to adequately source alterative sources of supply of wood waste, (xvi) currently applicable and proposed environmental regulation will be implemented, (xvii) weather, (xviii) availability and cost of labour and management resources, (xix) foreign exchange rates, (xx) the receipt of all required regulatory approvals, the approval of the Partnership's unitholders and Atlantic Power's shareholders of the Transaction with Atlantic Power, and the satisfaction of all other conditions precedent to the closing of the Transaction with Atlantic Power, and (xxi) factors and assumptions noted under Outlook in respect of the forward looking statements and information noted in that section.

        Whether actual results, performance or achievements will conform to the Partnership's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from the Partnership's expectations. Such risks and uncertainties include, but are not limited to risks and uncertainties relating to (i) the operation of the Partnership's facilities, (ii) plant availability and performance, (iii) the availability and price of energy commodities including natural gas and wood waste, (iv) the performance of counterparties in meeting their obligations under fuel supply, power purchase and other agreements, (v) competitive factors in the power industry, (vi) economic conditions, including in the markets served by the Partnership's facilities, (vii) changing demand for natural gas transportation on the TransCanada Canadian Mainline, (viii) ongoing compliance by the Partnership with its current debt covenants, (ix) developments within the North American capital markets and any lowering of credit ratings, (x) the availability and cost of permanent long term financing in respect of acquisitions and investments, significant capital expenditures, and refinancing of outstanding credit facilities at their maturity dates, (xi) unanticipated maintenance and other expenditures, (xii) the Partnership's ability to successfully realize the benefits of its capital projects, (xiii) changes in regulatory and government decisions including changes to environmental and financial reporting legislation, (xiv) waste heat availability and water flows, (xv) changes in existing and proposed tax and other legislation in Canada and the US and including changes in the Canada-US tax treaty, (xvi) the tax attributes of and implications of any acquisitions, (xvii) the availability and cost of labour, equipment and management resources, (xviii) the ability of the Partnership to adequately source alternative sources of supply of wood waste, (xix) the ability of the

Schedule VII-24


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Partnership to obtain Long-Term PPAs with satisfactory financial terms, (xx) seasonal contract pricing, (xxi) seasonal weather conditions, (xxii) fluctuations in US dollar exchange rates relative to the Canadian dollar, (xxiii) attainment of firm energy requirements, (xxiv) electricity load settlement, (xxv) the failure to receive any required regulatory approvals in connection with the Transaction with Atlantic Power, the failure to obtain the approval of the Partnership's unitholders and Atlantic Power's shareholders of the Transaction with Atlantic Power, or the failure to satisfy any other condition to the Transaction with Atlantic Power, and (xxvi) risks and uncertainties noted under Outlook in respect of the forward looking statements and information noted in that section. See also Business Risks in the Partnership's December 31, 2010 annual MD&A.

        Readers are cautioned not to place undue reliance on forward-looking statements as actual results could differ materially from the plans, expectations, estimates or intentions expressed in the forward-looking statements. Forward-looking statements are provided for the purpose of presenting information about management's current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. Except as required by law, the Partnership disclaims any intention and assumes no obligation to update any forward-looking statement.


QUARTERLY UNIT TRADING INFORMATION

        The Partnership units trade on the Toronto Stock Exchange under the symbol CPA.UN.

For the three months ended (unaudited)
  Jun. 30 2011   Mar. 31
2011
  Dec. 31
2010
  Sep. 30
2010
  Jun. 30
2010
 

Unit price

                               
 

High

 
$

21.05
 
$

21.22
 
$

19.02
 
$

18.85
 
$

18.14
 
 

Low

 
$

18.28
 
$

17.65
 
$

17.11
 
$

16.03
 
$

15.05
 
 

Close

 
$

19.00
 
$

20.90
 
$

17.95
 
$

18.75
 
$

16.30
 

Volume traded (millions)

   
6.9
   
5.0
   
4.4
   
4.2
   
5.1
 

        As at July 25, 2011, the Partnership had 56.6 million units outstanding. The weighted average number of units outstanding for the three and six months ended June 30, 2011 was 56.4 million and 56.2 million.


ADDITIONAL INFORMATION

        Additional information relating to Capital Power Income L.P. including the Partnership's Annual Information Form and other continuous disclosure documents are available on SEDAR at www.sedar.com.

Schedule VII-25