UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549



Amendment No. 1
to
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 March 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 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 02116
(Address of principal executive offices)
(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 o    No ý

         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 o    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 July 23, 2010 was 60,510,070.


Table of Contents


ATLANTIC POWER CORPORATION

FORM 10-Q

THREE MONTHS ENDED MARCH 31, 2010

Index

    General    
    CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION   2

 

 

PART I—FINANCIAL INFORMATION

 

4
ITEM 1.   CONSOLIDATED FINANCIAL STATEMENTS AND NOTES   4
        Consolidated Balance Sheets as of March 31, 2010 (unaudited) and
        December 31, 2009
  4
        Consolidated Statement of Operations for the three month periods ended
        March 31, 2010 and March 31, 2009 (unaudited)
  5
        Consolidated Statements of Cash Flows for the three month periods ended
        March 31, 2010 and March 31, 2009 (unaudited)
  6
        Notes to Consolidated Financial Statements (unaudited)   7
ITEM 2.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   27
ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK   44
ITEM 4.   CONTROLS AND PROCEDURES   47

 

 

PART II—OTHER INFORMATION

 

48
ITEM 1.   LEGAL PROCEEDINGS   48
ITEM 6.   EXHIBITS   48

Table of Contents

GENERAL

        In this 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 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.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

        Certain statements in this Quarterly Report on Form 10-Q, including documents incorporated by reference herein, constitute "forward-looking statements." 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 Securities and Exchange Commission. Our business is both competitive and subject to various risks.

        These risks include, without limitation:

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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. For a description of risks that could cause our actual results to materially differ from our current expectations, please see "Risk Factors" included in the filings we make from time to time with the Securities and Exchange Commission.

        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.

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PART I—FINANCIAL INFORMATION

ITEM 1.    CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

        


ATLANTIC POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands of U.S. dollars)

 
  March 31,
2010
  December 31,
2009
 
 
  (unaudited)
   
 

Assets

             

Current assets:

             
 

Cash and cash equivalents

  $ 44,356   $ 49,850  
 

Restricted cash

    22,385     14,859  
 

Accounts receivable

    17,130     17,480  
 

Current portion of derivative instruments asset (Notes 7 and 8)

    7,664     5,619  
 

Prepayments, supplies and other

    3,811     3,019  
 

Deferred income taxes

    20,302     17,887  
 

Refundable income taxes

    10,491     10,552  
           
 

Total current assets

    126,139     119,266  

Property, plant and equipment, net (Note 5)

   
191,515
   
193,822
 

Transmission system rights, net (Note 5)

    194,021     195,984  

Equity investments in unconsolidated affiliates

    260,694     259,230  

Other intangible assets, net (Note 5)

    72,651     71,770  

Goodwill

    8,918     8,918  

Derivative instruments asset (Notes 7 and 8)

    16,847     14,289  

Other assets

    5,892     6,297  
           
 

Total assets

  $ 876,677   $ 869,576  
           

Liabilities and Shareholders' Equity

             

Current liabilities:

             
 

Accounts payable and accrued liabilities

  $ 23,006   $ 21,661  
 

Current portion of long-term debt (Note 6)

    18,405     18,280  
 

Current portion of derivative instruments liability (Notes 7 and 8)

    9,693     6,512  
 

Interest payable on convertible debentures

    3,114     800  
 

Dividends payable

    5,423     5,242  
 

Other current liabilities

    495     752  
           
 

Total current liabilities

    60,136     53,247  

Long-term debt (Note 6)

    221,074     224,081  

Convertible debentures

    143,975     139,153  

Derivative instruments liability (Notes 7 and 8)

    14,139     5,513  

Deferred income taxes

    36,018     28,619  

Other non-current liabilities

    5,927     4,846  

Shareholders' equity:

             
 

Common shares

    541,917     541,917  
 

Accumulated other comprehensive loss (Note 8)

    (627 )   (859 )
 

Retained deficit

    (149,071 )   (126,941 )
 

Noncontrolling interest (Note 4)

    3,189      
           
 

Total shareholders' equity

    395,408     414,117  

Commitments and contingencies (Note 14)

             

Subsequent events (Notes 4, 10 and 15)

             
           
 

Total liabilities and shareholders' equity

  $ 876,677   $ 869,576  
           

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands of U.S. dollars, except per share amounts)

(Unaudited)

 
  Three months ended
March 31,
 
 
  2010   2009  

Project revenue:

             
 

Energy sales

  $ 15,913   $ 15,925  
 

Energy capacity revenue

    23,194     22,112  
 

Transmission services

    7,644     7,708  
 

Other

    470     289  
           

    47,221     46,034  

Project expenses:

             
 

Fuel

    16,157     14,961  
 

Operations and maintenance

    5,041     4,938  
 

Project operator fees and expenses

    919     1,273  
 

Depreciation and amortization

    10,071     10,666  
           

    32,188     31,838  

Project other income (expense):

             
 

Change in fair value of derivative instruments (Notes 7 and 8)

    (12,194 )   (109 )
 

Equity in earnings of unconsolidated affiliates

    5,436     4,951  
 

Interest, net

    (4,411 )   (4,504 )
           

    (11,169 )   338  
           

Project income

    3,864     14,534  

Administrative and other expenses (income):

             
 

Management fees and administration

    4,100     2,379  
 

Interest, net

    2,794     9,617  
 

Foreign exchange gain (Note 8)

    (1,792 )   (3,423 )
 

Other income, net

        (16 )
           

    5,102     8,557  
           

Income (loss) from operations before income taxes

    (1,238 )   5,977  

Income tax expense (Note 9)

    4,873     1,734  
           

Net income (loss)

    (6,111 )   4,243  

Less: Net loss attributable to noncontrolling interest

    (48 )    
           

Net income (loss) attributable to Atlantic Power Corporation

  $ (6,063 ) $ 4,243  
           

Net income (loss) per share attributable to Atlantic Power Corporation shareholders:

             
 

Basic

  $ (0.10 ) $ 0.07  
 

Diluted

  $ (0.10 ) $ 0.07  

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands of U.S. dollars)

(Unaudited)

 
  Three months ended March 31,  
 
  2010   2009  

Cash flows from operating activities:

             

Net (loss) income

  $ (6,111 ) $ 4,243  

Adjustments to reconcile to net cash provided by operating activities:

             
 

Depreciation and amortization

    10,071     10,666  
 

Loss on sale of property, plant and equipment

        333  
 

Distributions and equity in earnings from unconsolidated affiliates

    (4,102 )   1,121  
 

Unrealized foreign exchange gain

    (623 )   (3,980 )
 

Change in fair value of derivative instruments

    12,194     109  
 

Change in deferred income taxes

    4,829     1,655  
 

Change in other operating balances, net of acquisitions and disposition effects:

             
   

Accounts receivable

    350     5,979  
   

Prepayments, refundable income taxes and other assets

    (372 )   (2,244 )
   

Accounts payable and accrued liabilities

    2,290     (119 )
   

Other liabilities

    2,313     590  
           
 

Cash provided by operating activities

    20,839     18,353  
           

Cash flows from investing activities:

             
 

Acquisitions and investments, net of cash acquired

    324     (3,000 )
 

Change in restricted cash (Note 1)

    (7,526 )   (5,418 )
 

Biomass development costs

    (317 )    
 

Purchases of property, plant and equipment

    (319 )   (622 )
           
 

Cash used in investing activities

    (7,838 )   (9,040 )
           

Cash flows from financing activities:

             
 

Dividends paid

    (15,795 )   (5,593 )
 

Repayment of project-level debt

    (2,700 )   (1,306 )
           
 

Cash used in financing activities

    (18,495 )   (6,899 )
           

Increase (decrease) in cash and cash equivalents

    (5,494 )   2,414  

Cash and cash equivalents, beginning of period

    49,850     37,327  
           

Cash and cash equivalents, end of period

  $ 44,356   $ 39,741  
           

Supplemental cash flow information:

             
 

Interest paid

  $ 1,450   $ 10,201  
 

Income taxes paid (refunded)

  $ (26 ) $ 766  

See accompanying notes to consolidated financial statements.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of presentation

Overview

        Atlantic Power Corporation ("Atlantic Power") is a corporation established under the laws of the Province of Ontario 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 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.

        We currently own, through our wholly-owned subsidiaries Atlantic Power Transmission, Inc. and Atlantic Power Generation, Inc. indirect interests in 12 power generation projects and one transmission line located in the United States. Four of our Projects are wholly-owned subsidiaries: Lake Cogen, Ltd., Pasco Cogen, Ltd., Auburndale Power Partners, L.P. and Atlantic Path 15, LLC.

        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 atlanticpower.com. Our recent Canadian securities filings are available through our website.

        The interim consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles ("GAAP") with a reconciliation to Canadian GAAP in Note 16. The Canadian securities legislation allow 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.

        The interim consolidated financial statements do not contain all the disclosures required by United States and Canadian GAAP. The interim consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. The accounting policies we follow are set forth below in Note 2, Summary of significant accounting policies. The interim consolidated financial statements follow the same accounting principles and methods of application as the most recent annual consolidated financial statements as there are no material differences in our accounting policies between United States and Canadian GAAP at March 31, 2010 other than as denoted in Note 16. Interim results are not necessarily indicative of results for a 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 March 31, 2010, the results of operations for the three months ended March 31, 2010 and 2009, and our cash flows for the three months ended March 31, 2010 and 2009.

        Beginning in the first quarter of 2010, changes in restricted cash in the consolidated statement of cash flows has been reported as an investing activity to reflect the use of the restricted cash in the current period. In previous periods, changes in restricted cash were reported as cash flow from operating activities. The prior period amounts have been reclassified to conform with the current year presentation. This reclassification does not impact the consolidated balance sheet or the consolidated

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. Basis of presentation (Continued)


statements of operations. We have changed the classification of restricted cash because the revised presentation is more widely used by companies in our industry.

2. Summary of significant accounting policies

(a)
Basis of consolidation and accounting:

        The accompanying interim 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 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.

        As such, 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 will absorb a majority of the expected losses of the VIE, receive the majority of the expected residual returns of the VIE, or both. We have determined that our investments are not VIEs by evaluating their design and capital structure. Accordingly, we record all of our investments in less than 100% owned entities under the equity method of accounting.

        We eliminate all intercompany accounts and transactions in consolidation.

        These interim financial statements and notes reflect our evaluation of events occurring subsequent to the balance sheet date through July 23, 2010, the date the financial statements were issued.

(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, the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, 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)
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 power purchase agreements ("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.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)

        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.

(d)
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 7, for more information.

(e)
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. On occasion, 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 and the accounting treatment in the consolidated statements of operations of the changes in fair value of such derivative financial instrument:

Derivative financial instrument
  Location of changes in fair value
Foreign currency forward contracts   Foreign exchange loss (gain)
Lake natural gas swaps   Change in fair value of derivative instruments
Auburndale natural gas swaps   Change in fair value of derivative instruments
Interest rate swap   Change in fair value of derivative instruments

        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.

        We have designated one 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 within a designated hedging relationship 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.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)

(f)
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 as parts are replaced on the plant's combustion and steam turbines, these 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.

(g)
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.

(h)
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 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, an appropriate write-down is recorded based on the excess of the carrying value over the best estimate of fair value of the investment.

(i)
Other intangible assets:

        Other intangible assets include PPAs and fuel supply agreements at our projects.

        Power purchase agreements are valued at the time of acquisition based on the prices received under the PPAs compared to projected market prices. The balances are presented net of accumulated

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)


amortization in the consolidated balance sheets. Amortization is recorded on a straight-line basis over the remaining term of the PPA.

        Fuel supply agreements are valued at the time of acquisition based on the prices projected to be paid under the fuel supply agreement relative to projected market prices.

(j)
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 provide 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 9, for more information.

(k)
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.

(l)
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 and continued in effect until the end of 2009. On an annual basis, the Board of Directors of Atlantic Power establishes awards that are based on the cash flow performance of Atlantic Power in the most recently completed year, each participant's base salary and the market price of the shares at the award date. Awards are granted in the form of notional units that have similar economic characteristics to our common shares. Notional units vest ratably over a three-year period and are redeemed in a combination of cash and shares upon vesting.

        Unvested notional awards are entitled to receive dividends equal to the dividends per common share during the vesting period in the form of additional notional units. Unvested awards 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 at each balance sheet date. Fair value of the awards 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. Forfeitures are recorded as they occur and are not included in the estimated fair value of the awards. The aggregate number of shares which may be issued from treasury under the LTIP is limited to one million. All awards are accounted for as liability awards.

        In early 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 granted will be based, in part, on the total

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of significant accounting policies (Continued)


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 3-year cliff basis as opposed to ratable vesting over three years for grants made prior to the amendments. The amended LTIP is subject to shareholder approval.

(m)
Concentration of credit risk:

        The financial instruments that potentially expose us to credit risk consist primarily of cash, restricted cash, derivatives and accounts receivable. Cash and restricted cash are held by major financial institutions that are also counterparties to our derivative contracts. 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 12, Segment and related information, for a further discussion of customer concentrations.

(n)
Segments:

        We have six reportable segments: Path 15, Auburndale, Lake, Pasco, Chambers and Other Project Assets. Each of our projects is an operating segment. Based on similar economic and other characteristics, we aggregated several of the projects into the Other Project Assets reportable segment.

3. Comprehensive income (loss)

        The following table summarizes the components of comprehensive income (loss), net of tax of $11 and $2,395, respectively, for the three months ended March 31, 2010 and 2009:

 
  March 31,
2010
  March 31,
2009
 

Net income (loss)

  $ (6,111 ) $ 4,243  
 

Unrealized loss on hedging activity

    (16 )   (3,593 )
           

Comprehensive income (loss)

  $ (6,127 ) $ 650  
           

4. Acquisitions

Rollcast

        On March 31, 2009, we acquired a 40% equity interest in Rollcast Energy, Inc., a North Carolina Corporation for $3 million in cash consideration. Rollcast is a developer of biomass power plants in the southeastern U.S. with five, 50 MW 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. Two of the development projects have secured 20-year PPAs with terms that allow for fuel cost pass-through to the utility customer.

        On March 1, 2010, we paid $1.2 million in cash for an additional 15% of the shares of Rollcast, increasing our interest from 40% to 55% and providing us control of Rollcast. We consolidated Rollcast as of this date. We previously accounted for our 40% interest in Rollcast as an equity method investment.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Acquisitions (Continued)

        The following tables summarizes the consideration transferred to acquire Rollcast and the preliminary estimated amounts of identifiable assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the non-controlling 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 before acquisition date

    2,758  
 

Fair value of noncontrolling interest in Rollcast

    3,237  
       
 

Total

    7,195  
       

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  
 

Intangible assets

    3,151  
 

Trade and other payables

    (448 )
       
 

Total identifiable net assets

    7,195  
       

        The preliminary estimated fair value of the net assets acquired and the noncontrolling interest recorded are estimated based on their carrying values at the acquisition date. We expect to complete our fair value analysis of this acquisition during the second quarter of 2010.

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 March 31, 2010 and December 31, 2009:

 
  March 31,
2010
  December 31,
2009
 

Property, plant and equipment

  $ 77,359   $ 74,567  

Transmission system rights

    37,648     35,685  

Other intangible assets

    50,584     45,368  

6. Long-term debt

        Long-term debt represents our consolidated share of project long-term debt 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

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Long-term debt (Continued)


non-recourse to Atlantic Power and generally amortizes during the term of the respective revenue generating contracts of the projects.

 
  March 31,
2010
  December 31,
2009
 

Project debt, interest rates ranging from 5.1% to 9.0% maturing through 2028

  $ 227,630   $ 230,331  

Purchase accounting fair value adjustments

    11,849     12,030  

Less: current portion of long-term debt

    (18,405 )   (18,280 )
           

Long-term debt

  $ 221,074   $ 224,081  
           

        Project-level debt is secured by the respective projects and their contracts with no other recourse to us. At March 31, 2010, all of our projects were in compliance with the covenants contained in project-level debt.

7. Fair value of financial instruments

        The following represents the fair value hierarchy of our financial assets and liabilities that were recognized at fair value as of March 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.

 
  March 31, 2010  
 
  Level 1   Level 2   Level 3   Total  

Assets:

                         
 

Cash and cash equivalents

  $ 44,356   $   $   $ 44,356  
 

Restricted cash

    22,385             22,385  
 

Derivative instruments asset

        24,511         24,511  
                   
 

Total

  $ 66,741   $ 24,511   $   $ 91,252  
                   

Liabilities:

                         
 

Derivative instruments liability

  $   $ 23,832   $   $ 23,832  
                   
 

Total

  $   $ 23,832   $   $ 23,832  
                   

 

 
  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  
                   

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Fair value of financial instruments (Continued)

        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 March 31, 2010, the credit reserve resulted in a $0.5 million decrease in fair value which is comprised of a $0.8 million gain in change in fair value of derivative instruments offset by a $0.3 million loss in foreign exchange gain.

8. Accounting for derivative instruments and hedging activities

        We have elected to disclose derivative 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:

 
  March 31, 2010  
 
  Derivative
Assets
  Derivative
Liabilities
 

Derivatives designated as cash flow hedges:

             
 

Interest rate swap contract current

  $   $ 676  
 

Interest rate swap contract long-term

        244  
           

Total derivatives designated as cash flow hedges

        920  
           

Derivatives not designated as cash flow hedges:

             
 

Interest rate swap contract current

        1,738  
 

Interest rate swap contract long-term

        1,719  
 

Foreign currency forward contracts current

    7,664      
 

Foreign currency forward contracts long-term

    16,847      
 

Natural gas swap contracts current

        7,279  
 

Natural gas swap contracts long-term

        12,176  
           

Total derivatives not designated as cash flow hedges

    24,511     22,912  
           

Total derivatives

  $ 24,511   $ 23,832  
           

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Accounting for derivative instruments and hedging activities (Continued)

 

 
  December 31, 2009  
 
  Derivative
Assets
  Derivative
Liabilities
 

Derivatives designated as cash flow hedges:

             
 

Interest rate swap contract current

  $   $ 726  
 

Interest rate swap contract long-term

        167  
           

Total derivatives designated as cash flow hedges

        893  
           

Derivatives not designated as cash flow hedges:

             
 

Interest rate swap contract current

        1,705  
 

Interest rate swap contract long-term

        1,707  
 

Foreign currency forward contracts current

    5,619      
 

Foreign currency forward contracts long-term

    14,289      
 

Natural gas swap contracts current

    95     4,174  
 

Natural gas swap contracts long-term

    14     3,655  
           

Total derivatives not designated as cash flow hedges

    20,017     11,241  
           

Total derivatives

  $ 20,017   $ 12,134  
           

        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 contract in mid-2012 until the termination of its PPA.

        We continue to execute our 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 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 lives 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

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Accounting for derivative instruments and hedging activities (Continued)

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.

        The interest rate swap is a derivative financial instrument designated as a cash flow hedge. The instrument 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).

        Unrealized losses on interest rate swaps designated as cash flow hedges have been recorded in the consolidated statements of operations as a loss in other comprehensive income of $0.9 million for the three-month period ended March 31, 2010. Realized losses on these interest rate swaps of $0.2 million were recorded in interest expense, net for the three months ended March 31, 2010.

        Unrealized gains and losses on natural gas swaps designated as cash flow hedges are recorded in other comprehensive income in the consolidated statements of operations. 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 $0.4 million was recorded in change in fair value of derivative instruments for the three month period ended March 31, 2010.

        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 derivatives not designated as cash flow hedges:

 
  Location of (gain) loss
recognized in income
  Three months ended March 31, 2010  

Natural gas swaps

  Fuel   $ 1,818  

Foreign currency forwards

  Foreign exchange gain     (1,169 )

Interest rate swaps

  Interest, net     475  

        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 changes in the fair value of derivative financial instruments that are not designated as cash flow hedges for the three months ended March 31, 2010 and 2009:

 
  March 31, 2010   March 31, 2009  

Change in fair value of derivative instruments:

             
 

Interest rate swaps

  $ (46 ) $ (109 )
 

Natural gas swaps

    (12,148 )    
           

  $ (12,194 ) $ (109 )
           

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Accounting for derivative instruments and hedging activities (Continued)

        The following table summarizes the net notional volume buy/(sell) of our derivative transactions by type, excluding those derivatives that qualified for the normal purchases and normal sales exception as of March 31, 2010:

 
  Units   Total balance
as of
March 31,
2010
 

Interest rate swaps

  US$   $ 6,384  

Currency forwards

  Cdn$   $ 7,900  

Natural gas swaps

  Mmbtu     16,870  

        We use forward foreign currency contracts to manage our exposure to changes in foreign exchange rates, as we earn our income in the U.S. dollars but pay dividends to shareholders and interest on convertibles debentures predominantly in Canadian dollars. Since inception, we have established a hedging strategy for the purpose of reinforcing 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 of Cdn$1.134 per U.S. dollar in amounts sufficient to make monthly dividend payments at the current annual dividend level of Cdn$1.094 per common share, as well as interest payments on our 6.25% convertible debentures due March 15, 2017 (the "2009 Debentures"), through December 2013. It is our intention to periodically consider extending the length of these forward contracts.

        In addition, we have executed forward contracts to purchase Canadian dollars at fixed rates of exchange sufficient to make semi-annual payments on our 6.50% convertible secured debentures due October 31, 2014 (the "2006 Debentures"). The contracts provide for the purchase of Cdn$1.9 million in April and in October of each year through 2011 at a rate of Cdn$1.1075 per U.S. dollar.

        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 at March 31, 2010 is an asset of $24.5 million. 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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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Accounting for derivative instruments and hedging activities (Continued)

        The following table contains the components of recorded foreign exchange (gain) loss for the three months ended March 31, 2010 and 2009:

 
  March 31,
2010
  March 31,
2009
 

Unrealized foreign exchange (gain) loss:

             
 

Subordinated notes and convertible debentures

  $ (541 ) $ (12,767 )
 

Forward contracts and other

    (82 )   8,787  
           

    (623 )   (3,980 )

Realized foreign exchange (gains) losses on forward contract settlements

    (1,169 )   557  
           

  $ (1,792 ) $ (3,423 )
           

        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 March 31, 2010:

Convertible debentures

  $ 14,398  

Foreign currency forward contracts

    29,237  
       

  $ 43,635  

        The following table summarizes the effects of applying hedge accounting on accumulated other comprehensive income (loss) ("OCI") balance attributable to hedged derivatives, net of tax:

For the three month period ended March 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

    (16 )       (16 )

Realized from OCI during the period:
Due to amortization of de-designated cash flow hedges

        248     248  
               

Accumulated OCI balance at March 31, 2010

  $ (554 ) $ (73 ) $ (627 )
               

9. Income taxes

        The difference between the actual tax expense of $4.9 million for the three months ended March 31, 2010 and the expected income tax benefit of $(0.5) million is primarily due to an increase in the valuation allowance and various other permanent differences.

 
  March 31,
2010
  March 31,
2009
 

Current income tax expense

  $ 44   $ 79  

Deferred tax expense

    4,829     1,655  
           

Total income tax expense

  $ 4,873   $ 1,734  
           

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Income taxes (Continued)

        As of March 31, 2010, we have recorded a valuation allowance of $69.8 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.

10. Long-Term Incentive Plan

        The following table summarizes our LTIP activity as of March 31, 2010, and the changes during the three months then ended:

 
  Units   Grant Date
Weighted-Average
Price per Unit
 

Outstanding at December 31, 2009

    471,281   $ 7.30  

Granted

    138,892     12.66  

Additional shares from dividends

    10,566     7.30  

Vested

    (122,799 )   9.71  
           

Outstanding at March 31, 2010

    497,940     8.20  
           

        In early 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 granted 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 3-year cliff basis as opposed to ratable vesting over three years for grants made prior to the amendments. The amended LTIP is subject to shareholder approval.

11. 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, 2009. 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 three months ended March 31, 2010, the effect of including potentially dilutive shares in the calculation during the period is anti-dilutive.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Basic and diluted earnings (loss) per share (Continued)

        The following table sets forth the weighted average number of shares outstanding and potentially dilutive shares utilized in per share calculations for the three months ended March 31, 2010 and 2009:

 
  March 31,
2010
  March 31,
2009
 

Basic shares outstanding

    60,404     60,941  

Dilutive potential shares:

             
 

Convertible debentures

    11,473     4,839  
 

LTIP notional units

    394     308  
           

Potentially dilutive shares

    72,271     66,088  
           

12. 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 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 included in the table below.

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other
Project
Assets
  Un-allocated
Corporate
  Consolidated  

Period ended March 31, 2010:

                                                 

Operating revenues

  $ 7,644   $ 20,467   $ 16,241   $ 2,869   $   $   $   $ 47,221  

Segment assets

    223,467     126,191     118,320     41,693         7,131     359,875     876,677  

Project Adjusted EBITDA

 
$

7,053
 
$

9,371
 
$

7,313
 
$

1,415
 
$

5,988
 
$

7,655
 
$

 
$

38,795
 

Change in fair value of derivative instruments

        4,212     7,935         (173 )   546         12,520  

Depreciation and amortization

    2,099     4,948     2,269     746     837     5,487         16,386  

Interest, net

    3,146     471     (2 )       1,676     487         5,778  

Other project (income) expense

                    199     48         247  
                                   

Project income

    1,808     (260 )   (2,889 )   669     3,449     1,087         3,864  

Interest, net

                            2,794     2,794  

Administration

                            4,100     4,100  

Foreign exchange gain

                            (1,792 )   (1,792 )

Other expense, net

                                 

Loss from operations before income taxes

    1,808     (260 )   (2,889 )   669     3,449     1,087     (5,102 )   (1,238 )

Income tax expense (benefit)

                            4,873     4,873  
                                   

Net loss

    1,808     (260 )   (2,889 )   669     3,449     1,087     (9,975 ) $ (6,111 )
                                   

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Segment and related information (Continued)

 

 
  Path 15   Auburndale   Lake   Pasco   Chambers   Other
Project
Assets
  Un-allocated
Corporate
  Consolidated  

Period ended March 31, 2009:

                                                 

Operating revenues

  $ 7,708   $ 19,726   $ 15,864   $ 2,736   $   $   $   $ 46,034  

Segment assets

    239,691     145,398     128,860     45,911             334,201     894,061  

Project Adjusted EBITDA

 
$

6,902
 
$

8,162
 
$

7,897
 
$

1,970
 
$

6,152
 
$

9,988
 
$

 
$

41,071
 

Change in fair value of derivative instruments

                    (513 )   2,246         1,733  

Depreciation and amortization

    2,196     4,933     2,790     747     842     6,076         17,584  

Interest, net

    3,223     622     (6 )   (45 )   2,014     1,318         7,126  

Other project expense

                    202     (108 )       94  
                                   

Project income

    1,483     2,607     5,113     1,268     3,607     456         14,534  

Interest, net

                            9,617     9,617  

Management fees and administration

                            2,379     2,379  

Foreign exchange gain

                            (3,423 )   (3,423 )

Other expense, net

                            (16 )   (16 )

Income from operations before income taxes

    1,483     2,607     5,113     1,268     3,607     456     (8,557 )   5,977  

Income tax expense (benefit)

                            1,734     1,734  
                                   

Net income (loss)

    1,483     2,607     5,113     1,268     3,607     456     (10,291 ) $ 4,243  
                                   

        Progress Energy Florida and the California Independent System Operator ("CAISO") provide for 77.0% and 16.2%, respectively, of total revenues for the three months ended March 31, 2010 and 76.5% and 16.7% for the three months ended March 31, 2009. Progress Energy Florida purchases electricity from Auburndale and Lake and the CAISO makes payments to Path 15.

13. Related party transactions

        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 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 $8.1 million at December 31, 2009. The contract termination liability is being accreted to the final amounts due over the term of these payments.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. Commitments and contingencies

        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 March 31, 2010 which are expected to have a material impact on our financial position or results of operations.

15. Subsequent events

        These financial statements and notes reflect our evaluation of events occurring subsequent to the balance sheet date through July 23, 2010, the date the interim consolidated financial statements were issued.

        In April 2010, we invested an additional $0.8 million to increase our ownership interest in Rollcast to 60%. See Note 4 for additional information.

        On July 2, 2010, we acquired a 27.6% equity interest in Idaho Wind Partners 1, LLC ("IWP") for approximately $40.0 million. IWP recently commenced construction of a 183 MW wind power project located near Twin Falls, Idaho. IWP has 20-year Power Purchase Agreements with Idaho Power Company under which all electricity produced by the project can be sold at fixed prices. Our investment in IWP will be funded with cash on hand and a $20 million borrowing under our senior credit facility. Idaho Wind will be accounted for under the equity method of accounting.

16. 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 highlighting the material differences between our consolidated financial statements prepared in accordance with United States GAAP compared to its 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:

 
  Three-months ended
March 31,

 
 
  2010   2009  

Net income (loss), based on United States GAAP

  $ (6,111 ) $ 4,243  

Changes in fair value of power purchase agreement, net of tax(1)

    (12,301 )   (37,727 )

Projects accounted for under the cost method of accounting, net of tax(2)

    80     1,280  
           

Net income (loss), based on Canadian GAAP

  $ (18,332 ) $ (32,204 )
           

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. United States and Canadian accounting policy differences (Continued)

 

 
  March 31,
 
 
  2010   2009  

Shareholders' equity, based on United States GAAP

  $ 395,408   $ 146,668  

Adjusted for cumulative effect of US/Canadian differences

    71,679     41,115  
           

    467,087     187,783  

Net earnings for the period, Canadian GAAP

    (18,332 )   (32,204 )
           

Shareholders' equity, based on Canadian GAAP

  $ 448,755   $ 155,579  
           

(1)
The accounting standard 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 purchase and 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.

Earnings per share

 
  Three months ended March 31,  
 
  2010   2009  

Earnings per share under Canadian GAAP

             
 

Basic

  $ (0.30 ) $ (0.53 )
 

Diluted

  $ (0.30 ) $ (0.53 )

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. United States and Canadian accounting policy differences (Continued)

Condensed consolidated balance sheet

 
  March 31,
2010
  December 31,
2009
 
 
  (Canadian GAAP)
  (Canadian GAAP)
 

Assets

             

Current assets

  $ 146,323   $ 149,340  

Equity investments in unconsolidated affiliates(1)

    58,052     61,037  

Other long-term assets

    807,074     827,175  
           
 

Total assets

  $ 1,011,449   $ 1,037,552  
           

Liabilities and Shareholders' Equity

             

Current liabilities

  $ 82,431   $ 77,471  

Other non-current liabilities

    480,263     480,398  

Shareholders' equity:

             
 

Common shares

    541,304     541,304  
 

Accumulated other comprehensive loss

    (627 )   (859 )
 

Retained deficit

    (95,111 )   (60,762 )
 

Noncontrolling interest

    3,189      
           
 

Total shareholders' equity

    448,755     479,683  
           
 

Total liabilities and shareholders' equity

  $ 1,011,449   $ 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.

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ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. United States and Canadian accounting policy differences (Continued)

 
  March 31, 2010   March 31, 2009  
 
  (Canadian GAAP)
  (Canadian GAAP)
 

Project Income

             
 

Project revenue

  $ 77,627   $ 83,551  
 

Project expenses

    57,232     63,280  
 

Project other expenses

    (43,135 )   (66,599 )
           

    (22,740 )   (46,328 )

Administration and other expenses, net

   
5,102
   
8,557
 
           

Loss from operations before income taxes

    (27,842 )   (54,885 )

Income tax expense benefit

    (9,510 )   (22,681 )
           

Net loss

    (18,332 )   (32,204 )

Less: Net loss attributable to noncontrolling interest

    (48 )    
           

Net loss attributable to Atlantic Power Corporation

  $ (18,284 ) $ (32,204 )
           

 
  March 31, 2010   March 31, 2009  
 
  (Canadian GAAP)
  (Canadian GAAP)
 

Cash provided by operating activities

  $ 23,578   $ 21,622  

Cash used in investing activities

    (9,191 )   (10,457 )

Cash used in financing activities

    (21,258 )   (9,513 )
           

Increase in cash and cash equivalents

   
(6,871

)
 
1,652
 

Cash and cash equivalents, beginning of period

    54,503     50,071  
           

Cash and cash equivalents, end of period

 
$

47,632
 
$

51,723
 
           

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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 is a leading independent power producer, with power projects located in major markets in the United States. Our current portfolio consists of interests in 12 operational power generation projects across eight states, a 500 kilovolt 84-mile electric transmission line located in California, and six development projects in five states. Our power generation projects have an aggregate gross electric generation capacity of approximately 1,823 megawatts (or "MW"), in which our ownership interest is approximately 808 MW.

        We sell the capacity and energy from our projects under power purchase agreements (or "PPAs") with a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2010 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 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 most 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 independent power industry to operate and maintain our projects, including Caithness Energy, LLC 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 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 V6C 2G8 and our headquarters are located at 200 Clarendon Street, Floor 25, Boston, Massachusetts, USA 02116. Our website is atlanticpower.com. Information contained on our website is not part of this Quarterly Report on Form 10-Q.

        We completed our initial public offering on the Toronto Stock Exchange (TSX: ATP) in November 2004.

        As of July 23, 2010, we have 60,510,070 common shares, Cdn$60 million principal amount of 6.50% convertible secured debentures due October 31, 2014 (the "2006 Debentures"), and Cdn$86.25 million principal amount of 6.25% convertible debentures due March 15, 2017 (the "2009 Debentures" and together with 2006 Debentures, the "Debentures") outstanding. The 2006 Debentures and the 2009 Debentures are convertible at any time, at the option of the holder, into 80.645 and 76.923 common shares per Cdn$1,000 principal amount of Debentures, respectively, representing a conversion price of Cdn$12.40 and Cdn$13.00, respectively, per common share. Holders of common shares receive a monthly dividend at a current annual rate of Cdn$1.094 per common share.

        On November 24, 2009, our shareholders approved the conversion from the previous Income Participating Security ("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 part of an IPS

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was exchanged for approximately 0.44 of a new common share. This transaction resulted in the extinguishment of Cdn$347,832 principal value of 11% Subordinated Notes due 2016 that previously formed a part of each IPS.

OUR POWER PROJECTS

        The following table outlines the Company's portfolio of power generating and transmission assets in operation as of July 23, 2010, including its interest in each facility. Management believes the portfolio is well diversified based on 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)

  Accounting
Treatment(2)

  Net
MW(3)

  Electricity
Purchaser

  Power
Contract
Expiry

  Customer
S&P Credit
Rating


 
Auburndale   Florida   Natural Gas     155     100.0 % C     155   Progress Energy Florida     2013   BBB+

 
Lake   Florida   Natural Gas     121     100.0 % C     121   Progress Energy Florida     2013   BBB+

 
Pasco   Florida   Natural Gas     121     100.0 % C     121   Tampa Electric Co.     2018   BBB

 
Chambers   New Jersey   Coal     262     40.0 % E     89   ACE(4)     2024   BBB
                             
 
                              16   DuPont     2024   A

 
Path 15   California   Transmission     N/A     100.0 % C     N/A   California Utilities via CAISO(5)     N/A (6) BBB+ to A(7)

 
Orlando   Florida   Natural Gas     129     50.0 % E     46   Progress Energy Florida     2023   BBB+
                             
 
                              19   Reedy Creek Improvement District     2013 (8) A(9)

 
Selkirk   New York   Natural Gas     345     18.50% (10) E     15   Merchant     N/A   N/R
                             
 
                              49   Consolidated Edison     2014   A-

 
Gregory   Texas   Natural Gas     400     17.10 % E     59   Fortis Energy Marketing and Trading     2013   A-
                             
 
                              9   Sherwin Alumina     2020   NR

 
Topsham(11)   Maine   Hydro     14     50.0 % E     7   Central Maine Power     2011   BBB+

 
Badger Creek   California   Natural Gas     46     50.0 % E     23   Pacific Gas & Electric     2011   BBB+

 
Rumford   Maine   Coal/Biomass     85     23.50% (10) E     20   Rumford Paper Co.     2010   N/R

 
Koma Kulshan   Washington   Hydro     13     49.80 % E     6   Puget Sound Energy     2037   BBB

 
Delta-Person   New Mexico   Natural Gas     132     40.0 % E     53   PNM     2020   BB-

 
Idaho Wind   Idaho   Wind     183     27.56 % E     51   Idaho Power Co.     2030   BBB

 
(1)
Except as otherwise noted, economic interest represents the percentage ownership interest in the Project held indirectly by Atlantic Power.

(2)
Accounting Treatment: C—Consolidated and E—Equity Method of Accounting

(3)
Represents our interest in each Project's electric generation capacity based on our economic interest.

(4)
Includes 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.

(5)
California utilities pay transmission access charges ("TACs") to CAISO, who then pays owners of TSRs, such as Path 15, in accordance with its FERC approved annual revenue requirement.

(6)
Path 15 is a FERC regulated asset with a FERC-approved regulatory life of 30 years through 2034.

(7)
Largest payers of TACs supporting Path 15's annual revenue requirement are PG&E (BBB+), SoCal Ed (BBB+) and SDG&E (A). CAISO imposes minimum credit quality requirements for any participants of A or better unless collateral is posted per CAISO imposed schedule.

(8)
Upon the expiry of the Reedy Creek PPA, the associated capacity and energy will be sold to PEF.

(9)
Fitch rating on Reedy Creek Improvement District bonds.

(10)
Represents our estimated share of the cash flow from the Project.

(11)
The Company owns its interest in this Project as a lessor.

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Recent Developments

        In March 2010, we invested an additional $1.2 million to increase our ownership interest in Rollcast to 55%. As a result of this additional investment, we have consolidated our investment in Rollcast beginning on March 1, 2010. In April 2010, we invested an additional $0.8 million to bring our total ownership interest to 60%. During the second quarter 2010, Rollcast executed an engagement letter and term sheet with two banks to co-arrange debt financing and also entered into a construction agreement for its first 50 MW biomass project in Barnesville, Georgia.

        On July 2, 2010, we acquired a 27.6% equity interest in Idaho Wind Partners 1, LLC ("IWP") for approximately $40.0 million. IWP recently commenced construction of a 183 MW wind power project located near Twin Falls, Idaho. IWP has 20-year Power Purchase Agreements with Idaho Power Company under which all electricity produced by the project can be sold at fixed prices. Our investment in IWP will be funded with cash on hand and a $20 million borrowing under our senior credit facility. Idaho Wind will be accounted for under the equity method of accounting.

        In April 2010, we filed an initial registration statement on Form 10 with the U.S. Securities and Exchange Commission. Our registration statement became effective on July 21, 2010 and we listed our common shares on the New York Stock Exchange on July 23, 2010. Beginning with the first quarter 2010, Atlantic Power is reporting under U.S. GAAP. Amounts reported in previous periods under Canadian GAAP have been conformed to U.S. GAAP in this Quarterly Report on Form 10-Q, which has been filed in both Canada and the U.S.

Critical Accounting Policies and Estimates

        Accounting standards require information 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 and the fair value of derivatives.

        For a summary of our significant accounting policies, see Note 2 to our interim consolidated financial statements included elsewhere in this Form 10-Q. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows.

        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

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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.

        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, 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

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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 counterparty'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 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.

        As of March 31, 2010, we had recorded a valuation allowance of $69.8 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.

Non-GAAP Financial Measures

        Cash Flow 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 Flow 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 Flow Available for Distribution is set out below under "Cash Flow Available for Distribution". Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

        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.

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Results of Operations

        The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2010 and 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

(Unaudited)
(in thousands of U.S. dollars, except as otherwise stated)
  March 31,
2010
  March 31,
2009
 

Project revenue

             
 

Auburndale

  $ 20,467   $ 19,726  
 

Lake

    16,241     15,864  
 

Pasco

    2,869     2,736  
 

Path 15

    7,644     7,708  
 

Chambers

         
 

Other Project Assets

         
           

    47,221     46,034  

Project expenses

             
 

Auburndale

    16,044     16,498  
 

Lake

    11,197     10,757  
 

Pasco

    2,200     1,513  
 

Path 15

    2,690     3,002  
 

Chambers

         
 

Other Project Assets

    57     68  
           

    32,188     31,838  

Project other income (expense)

             
 

Auburndale

    (4,683 )   (621 )
 

Lake

    (7,933 )   6  
 

Pasco

        45  
 

Path 15

    (3,146 )   (3,223 )
 

Chambers

    3,449     3,607  
 

Other Project Assets

    1,144     524  
           

    (11,169 )   338  

Total project income

             
 

Auburndale

    (260 )   2,607  
 

Lake

    (2,889 )   5,113  
 

Pasco

    669     1,268  
 

Path 15

    1,808     1,483  
 

Chambers

    3,449     3,607  
 

Other Project Assets

    1,087     456  
           

    3,864     14,534  

Administrative and other expenses

             
 

Management fees and administration

    4,100     2,379  
 

Interest, net

    2,794     9,617  
 

Foreign exchange loss (gain)

    (1,792 )   (3,423 )
 

Other expense, net

        (16 )
           

Total administrative and other expenses

    5,102     8,557  
           

(Loss) income from operations before income taxes

    (1,238 )   5,977  

Income tax expense

    4,873     1,734  
           

Net (loss) income

    (6,111 )   4,243  

Less: Net loss attributable to noncontrolling interest

    (48 )    
           

Net income (loss) attributable to Atlantic Power Corporation shareholders

  $ (6,063 ) $ 4,243  
           

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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 flow available for distribution was $17.8 million and $24.1 million for the three months ended March 31, 2010 and 2009, respectively. See "Cash Flow Available for Distribution" on page 34 for additional information.

        Income (loss) from operations before income taxes for the three months ended March 31, 2010 and 2009, was $(1.2) million and $6.0 million, respectively. See "Project Income" below for additional information.

Three months ended March 31, 2010 compared with three months ended March 31, 2009

Project Income

        Project income (loss) for our Auburndale segment decreased $2.9 million to $(0.3) million in the three-month period ended March 31, 2010 from $2.6 million in the comparable 2009 period. The decrease in project income for the three months ended March 31, 2010 is attributable to the $4.2 million 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 the changes in market prices of natural gas. See "Quantitative and Qualitative Disclosures About Market Risk" below for additional details about our derivative instruments and other financial instruments. In addition, operations and maintenance costs were lower at Auburndale in the 2010 period due to timing.

        Project income (loss) for our Lake segment decreased $8.0 million to $(2.9) million in the three-month period ended March 31, 2010 from $5.1 million in the comparable 2009 period. The decrease is primarily attributable to the $7.9 million 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 the changes in market prices of natural gas. See "Quantitative and Qualitative Disclosures About Market Risk" below for additional details about our derivative instruments and other financial instruments.

        Project income for our Pasco segment decreased $0.6 million, or 47%, to $0.7 million in the three-month period ended March 31, 2010 from $1.3 million in the comparable 2009 period. The decrease in project income at Pasco is attributable to the timing of operation and maintenance costs.

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        Project income for our Path 15 segment increased $0.3 million, or 22%, to $1.8 million in the three-month period ended March 31, 2010 from $1.5 million in the comparable 2009 period. The increase in project income at Path 15 is attributable to lower operation and maintenance costs associated with vegetation mitigation.

        Project income for our Chambers segment, which is recorded under the equity method of accounting, did not change significantly from March 31, 2009.

        Project income (loss) for our Other Project Assets segment increased $0.6 million, to $1.1 million for the three months ended March 31, 2010 compared to a $0.5 million income in the comparable 2009 period. While the overall change in project income for the segment was not significant, some of the components of the change are as follows:

Administrative and Other Expenses (Income)

        Management fees and administration increased $1.7 million, or 72%, to $4.1 million for the three months ended March 31, 2010 from $2.4 million in the comparable period in 2009. The increase is primarily attributable to higher 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 first quarter of 2010 compared to the first quarter of 2009, resulting in higher expense in the 2010 period. In addition, we incurred additional expense associated with preparation of our planned New York Stock Exchange listing, expected to be completed during the second quarter of 2010.

        Interest expense primarily relates to the convertible debentures. Interest expense decreased $6.8 million, or 71%, to $2.8 million in 2010 from $9.6 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$347,832 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. 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) decreased $1.6 million to a $1.8 million gain in 2010 compared to a $3.4 million gain in 2009. The U.S. dollar to Canadian dollar exchange rate decreased by 3.5% during the three months ended March 31, 2010. During the three months ended March 31, 2009, the rate increased by 3.4%. See "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 three months ended March 31, 2010 compared to the foreign exchange loss (gain) in the comparable quarter of 2009.

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Supplementary Financial Information

        The key measure we use to evaluate the results of our projects is Cash Flow Available for Distribution. See "Cash Flow Available for Distribution" below for additional details and for a reconciliation of Cash Flow Available for Distribution to its nearest GAAP measure, cash flows from operating activities.

        The primary factor influencing Cash Flow 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. Please read "Non-GAAP Financial Measures" above for important disclosures with respect to Cash Flow Available for Distribution and Project Adjusted EBITDA.

        Because Project Adjusted EBITDA and project distributions are key drivers of both the performance of our projects and Cash Flow 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.

Project Adjusted EBITDA(1) (in thousands of U.S. dollars) for the three months ended March 31, 2010 and 2009:

(unaudited)
  March 31,
2010
  March 31,
2009
 

Project Adjusted EBITDA(1) by individual segment

             
 

Auburndale

    9,371     8,162  
 

Lake

    7,313     7,897  
 

Pasco

    1,415     1,970  
 

Path 15

    7,053     6,902  
 

Chambers

    5,988     6,152  
           

Total

    31,140     31,083  

Other Project Assets

             
 

Mid-Georgia

        758  
 

Stockton

        145  
 

Badger Creek

    736     1,220  
 

Koma Kulshan

    119     (43 )
 

Orlando

    1,801     1,840  
 

Topsham

    415     415  
 

Delta Person

    364     434  
 

Gregory

    855     1,158  
 

Rumford

    (8 )   656  
 

Selkirk

    3,530     3,569  
 

Other

    (157 )   (164 )
           

Total adjusted EBITDA(1) from Other Project Assets segment

    7,655     9,988  

Project income

             

Total adjusted EBITDA(1) from all Projects

    38,795     41,071  

Amortization

    16,386     17,584  

Interest expense, net

    5,778     7,126  

Change in the fair value of derivative instruments

    12,520     1,733  

Other (income) expense

    247     94  
           

Project income as reported in the statement of operations

    3,864     14,534  
           

(1)
Project Adjusted EBITDA is a non-GAAP measure. See "Non-GAAP Financial Measures" on Page 26 of this Quarterly Report on Form 10-Q for additional details.

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Reconciliation of Project Distributions (in thousands of U.S. dollars)
For the three months ended March 31, 2010

 
  Project
Adjusted
EBITDA(1)
  Repayment
of long-
term debt
  Interest
expense,
net
  Capital
expenditures
  Change in
working
capital &
other items
  Project
distribution
received
 

Reportable Segments

                                     
 

Auburndale

    9,371     (2,450 )   (471 )       (650 )   5,800  
 

Chambers

    5,988     (3,013 )   (1,676 )   (34 )   (1,265 )    
 

Lake

    7,313         2     (274 )   (1,011 )   6,030  
 

Pasco

    1,415             (24 )   (361 )   1,030  
 

Path 15

    7,053         (3,146 )       (3,907 )    
                           

Total Reportable Segments

    31,140     (5,463 )   (5,291 )   (332 )   (7,194 )   12,860  
                           

Other Project Assets

                                     
 

Badger Creek

    736         6         92     834  
 

Delta Person

    364     (662 )   (69 )       367      
 

Gregory

    855     (394 )   206         (349 )   318  
 

Koma Kulshan

    119                 63     182  
 

Orlando

    1,801         (33 )   (43 )   (1,725 )    
 

Rumford

    (8 )               8      
 

Selkirk

    3,530         (600 )       (2,930 )    
 

Topsham

    415                 (415 )    
 

Other

    (157 )       3     (21 )   175      
                           

Total Other Project Assets Segment

    7,655     (1,056 )   (487 )   (64 )   (4,714 )   1,334  
                           

Total all Segments

    38,795     (6,519 )   (5,778 )   (396 )   (11,908 )   14,194  
                           

(1)
Project Adjusted EBITDA is a non-GAAP measure. See "Non-GAAP Financial Measures" on Page 26 of this Quarterly Report on Form 10-Q for additional details.

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Reconciliation of Project Distributions (in thousands of U.S. dollars)
For the three months ended March 31, 2009

 
  Project
Adjusted
EBITDA(1)
  Repayment
of long-
term debt
  Interest
expense,
net
  Capital
expenditures
  Change in
working
capital &
other items
  Project
distribution
received
 

Reportable Segments

                                     
 

Auburndale

    8,162     (875 )   (622 )   (209 )   2,104     8,560  
 

Chambers

    6,152     (2,637 )   (2,014 )   (238 )   (1,263 )    
 

Lake

    7,897         6     (214 )   71     7,760  
 

Pasco

    1,970         45     (174 )   3,459     5,300  
 

Path 15

    6,902         (3,223 )       (3,679 )    
                           

Total Reportable Segments

    31,083     (3,512 )   (5,808 )   (835 )   692     21,620  
                           

Other Project Assets

                                     
 

Mid-Georgia

    758     (408 )   (875 )       525      
 

Stockton

    145         (15 )       (130 )    
 

Badger Creek

    1,220         (3 )       233     1,450  
 

Delta Person

    434     (263 )   (98 )       (73 )    
 

Gregory

    1,158     (1,754 )   441     (34 )   189      
 

Koma Kulshan

    (43 )               104     61  
 

Orlando

    1,840         4     (1 )   2,482     4,325  
 

Rumford

    656                 (656 )    
 

Selkirk

    3,569         (772 )   (30 )   (2,767 )    
 

Topsham

    415         (1 )       (414 )    
 

Other

    (164 )       1     (23 )   423     237  
                           

Total Other Project Assets Segment

    9,988     (2,425 )   (1,318 )   (88 )   (84 )   6,073  
                           

Total all Segments

    41,071     (5,937 )   (7,126 )   (923 )   608     27,693  
                           

(1)
Project Adjusted EBITDA is a non-GAAP measure. See "Non-GAAP Financial Measures" on Page 26 of this Form 10-Q for additional details.

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Project Operations Performance—Three months ended March 31, 2010 compared with three months ended March 31, 2009

        Aggregate Project Adjusted EBITDA for the segments decreased $2.3 million, or 6%, to $38.8 million in the three months ended March 31, 2010 from $41.1 million in 2009 and included the following factors:

        Aggregate power generation for projects in operation at March 31, 2010 was 11.1% lower during the three-month period ended March 31, 2010 compared to the comparable 2009 period. Weighted average plant availability increased 3.9% over the same period. Generation during the first three months of 2010 compared to the prior year period was unfavorably impacted primarily by reduced dispatch at the Chambers and Selkirk projects due to lower power prices and the absence of Stockton and Mid-Georgia generation as the projects were sold in the fourth quarter of 2009, offset slightly by increased generation at Gregory due to a scheduled outage in the first quarter of 2009.

        The project portfolio achieved a weighted average availability of 98.6% for the three-months ended March 31, 2010 compared to 94.7% in the 2009 period. The increase in portfolio availability in the first quarter of 2010 was primarily due to the planned outages at Gregory and Selkirk in the first quarter of 2009. 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 $2.5 million for the three months ended March 31, 2010 over the comparable period in 2009. The changes from the prior period are consistent with and partially attributable to the changes in Project Adjusted EBITDA described above, as well as changes in working capital at both consolidated and unconsolidated affiliates.

        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.

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        Cash flows used in investing activities for the three months ended March 31, 2010 were $7.8 million compared to $9.0 million for the three months ended March 31, 2009. We invested $3.0 million in Rollcast during the first quarter of 2009, compared to an additional $1.2 million investment in Rollcast during first quarter 2010. The cash consolidated in our balance sheet as a result of the additional investment in Rollcast was $1.5 million.

        Cash used in financing activities for the three months ended March 31, 2010 resulted in a net outflow of $18.5 million compared to a net outflow of $6.9 million for the same period in 2009. The increase relates to higher dividends paid in the 2010 period. We completed our common share conversion in November 2009. As a result, Cdn$347.8 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 three months ended March 31, 2009.

Cash Flow 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. Cash Flow Available for Distribution decreased by $6.3 million for the three months ended March 31, 2010 from the 2009 period as set forth in the following table:

(unaudited)
(in thousands of U.S. dollars, except as otherwise stated)
  March 31,
2010
  March 31,
2009
 

Cash flows from operating activities(1)

    20,839     18,353  

Project-level debt repayments

    (2,700 )   (1,306 )

Interest on IPS portion of subordinated notes(2)

        7,713  

Purchases of property, plant and equipment

    (319 )   (622 )
           

Cash Flow Available for Distribution(3)

    17,820     24,138  

Interest on subordinated notes

   
   
7,713
 

Dividends on common shares

    15,801     5,593  
           

Total distributions to shareholders

    15,801     13,306  

Payout ratio

   
89

%
 
55

%

Expressed in Cdn$

             

Cash Flow Available for Distribution

    18,540     30,034  

Total distributions to shareholders

   
16,527
   
16,673
 

(1)
Beginning in the first quarter of 2010, changes in restricted cash in the consolidated statement of cash flows has been reported as an investing activity to reflect the use of the restricted cash in the current period. In previous periods, changes in restricted cash were reported as cash flow from operating activities. The prior period amounts have been reclassified to conform with the current year presentation. This reclassification does not impact the consolidated balance sheet or the consolidated statements of operations. We have changed the classification of restricted cash because the revised presentation is more widely used by companies in our industry.

(2)
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

(3)
Cash Flow 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 "Non-GAAP Financial Measures".

Outlook

        Based on year-to-date results and our projections for the remainder of the year, we expect to receive distributions from our projects in the range of $70 million to $77 million for the full year 2010, resulting in a payout ratio estimated to be near 100%. This amount represents a decrease of

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approximately $23 million to $30 million compared to distributions received from the projects in 2009. Additional details about these changes are included below.

        At the corporate-level, we expect a net cash tax refund in 2010 in the range of $7 million to $9 million, compared to insignificant net cash taxes in 2009. Included in 2010 corporate-level costs will be the $5 million payment under the terms of the management agreement termination, down from the $6 million payment in 2009.

        The 2010 reductions in project distributions have historically been included in our long-term cash flow projections when we periodically confirm our ability to continue paying dividends to shareholders at current levels.

        Looking ahead to 2011, we expect overall levels of cash flow and the payout ratio to be generally consistent with 2010. Higher project distributions and a slightly lower payment under the management agreement termination are expected to be offset by the non-recurrence of the cash tax refunds that are anticipated in 2010. In 2012, still higher distributions from projects are expected to increase operating cash flow and reduce the payout ratio significantly compared to 2010 and 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 one-time items and contract expirations comprise the most significant of the decreases in projected 2010 project distributions compared to 2009.

        In 2009, the following five projects comprised approximately 86% of project distributions received: Auburndale, Lake, Orlando, Path 15 and Pasco. For 2010, we expect these same five projects to contribute a similar proportion of total project distributions.

        In addition to the items above, the following is a summary of other projections for project distributions in 2010 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 the expiration of its PPA in July, 2013. 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 required at the project. We have taken advantage of the low market price of natural gas to make significant progress in our natural gas hedging strategy. These hedges are summarized below under "Quantitative and Qualitative Disclosures About Market Risk". We intend to continue, when appropriate, to evaluate opportunities to further mitigate natural gas price exposure at Lake in 2011 and 2013, but do not intend to execute additional hedges at Lake for 2010 or 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 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.

        We expect to receive distributions from the Lake project of approximately $25 million to $27 million in 2010. In 2011 and 2012, expected distributions from Lake are expected to be $28 million

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to $32 million per year. The increases in 2011 and 2012 are primarily due to higher contractual capacity revenue and lower hedged natural gas prices than in 2010. These estimated distributions are based on our current internal models as of July 23, 2010. Our models are based on future natural gas prices forecasted by Cambridge Energy Research Associates, an independent third-party energy consulting firm.

        Coal prices used in the electricity 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.

Auburndale

        Based on the current forecast, we expect distributions from Auburndale of $24 million to $26 million per year from 2010 through 2013, when the project's current PPA expires. Distributions received from Auburndale in the 2010 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 coal costs 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 throughout the PPA's expiration in mid-2012. 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. See "Quantitative and Qualitative Disclosures About Market Risk" for additional details about hedge contracts executed as of July 23, 2010. The 2010 and 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 the 2012 to 2013 period.

Chambers

        As expected, we reported a significant decrease in cash flow at the Chambers project in 2009 due to a planned major maintenance outage during the year, changes in market power prices and expected sales volumes and the expense associated with regional carbon allowance purchases.

        As previously reported, the 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 do not expect to receive distributions from Chambers in 2010. Based on our current projections, we will resume receiving distributions from the project in early 2011 based on meeting the required debt service coverage ratios.

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.

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        We do not expect any material unusual requirements for cash outflows in 2010 for capital expenditures or other required investments. In addition, there are no debt instruments with significant maturities or refinancing requirements in 2010. See "Outlook" above for information about changes in expected distributions from our projects in 2010.

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 1.50% and 3.25% that varies based on the credit statistics of one of our subsidiaries. As of March 31, 2010, the applicable margin was 1.875%. As of March 31, 2010, $39.4 million was allocated, but not drawn, to support letters of credit for contractual credit support at seven 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 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.

Convertible Debentures

        On October 11, 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.

        In December 2009, we issued, in a public offering, Cdn$86.25 million aggregate principal amount of 6.25% convertible debentures, which we refer to as the 2009 Debentures, for gross proceeds of $71.4 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.

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 March 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 March 31, 2010, the covenants at the Chambers, Selkirk and Delta-Person projects are temporarily preventing those projects from making cash distributions to us. We expect these projects to resume cash distributions in 2011. See "Outlook" above for guidance

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related to the Chambers project. All project-level debt is non-recourse to us and substantially all of the principal is amortized over the life of the projects' PPAs.

        The range of interest rates presented represents the rates in effect at March 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
  2010   2011   2012   2013   2014   Thereafter  

Consolidated Projects:

                                               
 

Epsilon Power Partners

  8.4%     37,232     750     1,500     1,500     3,000     5,000     25,482  
 

Path 15

  7.9%–9.0%     161,348     7,480     7,987     8,667     9,402     8,065     119,747  
 

Auburndale

  5.1%     29,050     7,350     9,800     7,000     4,900          
                                   

Total Consolidated Projects

        227,630     15,580     19,287     17,167     17,302     13,065     145,229  

Equity Method Projects:

                                               
 

Chambers

  0.4%–7.2%     83,333     8,288     11,294     12,176     10,783     5,780     35,012  
 

Delta-Person

  2.1%     11,420     485     1,220     1,308     1,403     1,505     5,499  
 

Selkirk

  9.0%     25,655     8,862     10,948     5,845              
 

Gregory

  1.8%–7.5%     15,647     1,364     1,901     2,044     2,205     2,385     5,748  
                                   

Total Equity Method Projects

        136,055     18,999     25,363     21,373     14,391     9,670     46,259  
                                   

Total Project-Level Debt

        363,685     34,579     44,650     38,540     31,693     22,735     191,488  
                                   

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 March 31, 2010, restricted cash at consolidated projects totaled $22.4 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 2010, several of the projects have planned outages to complete maintenance work. The level of maintenance and capital expenditures is reduced from 2009. Selkirk has planned a major overhaul of a steam turbine and a minor inspection of one of its combustion turbines, with costs and lost margin largely covered by reserves and gas resales, respectively. Auburndale will also conduct a minor inspection of one of the facility's combustion turbines, which is covered by its long-term service agreement, in conjunction with other maintenance work. Chambers is scheduled to conduct inspections and customary repairs on both its boilers. Typically, Chambers staggers the inspections of its two boilers from year to year; however the boiler inspection in 2009 was deferred to 2010 in order to preserve a high availability factor given the anticipated reduced availability associated with the project's steam turbine overhaul in 2009. A minor gas turbine inspection is also scheduled at Orlando.

Off-Balance Sheet Arrangements

        As of March 31, 2010, 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 are 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 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.

        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 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 2010, 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 2010, projected cash distributions at Lake would change by approximately $0.7 million per $1.00/Mmbtu change in the price of natural gas based on the current level of unhedged 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 July 23, 2010:

 
  2010   2011   2012   2013  

Portion of gas volumes currently hedged:

                         
 

Lake:

                         
   

Contracted

                 
   

Financially hedged

    80 %   78 %   90 %   65 %
                   
   

Total

    80 %   78 %   90 %   65 %
                   
 

Auburndale:

                         
   

Contracted

    80 %   80 %   40 %    
   

Financially hedged

    15 %   13 %   32 %   79 %
                   
   

Total

    95 %   93 %   72 %   79 %
                   

Average price of financially hedged volumes (per Mmbtu)

                         
 

Lake

  $ 7.11   $ 6.52   $ 6.90   $ 7.05  
 

Auburndale

  $ 6.30   $ 6.68   $ 6.51   $ 6.92  

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 the U.S. dollars but pay dividends to shareholders in Canadian dollars. Since our inception, we have had an established hedging strategy for the purpose of reinforcing 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 sufficient to make monthly dividend payments at the current annual dividend level of Cdn$1.094 per common share, as well as interest payments on the 2009 Debentures, through December 2013. It is our intention to periodically consider extending the length of these forward contracts. 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.

        In addition to the forward contracts discussed above that settle on a monthly basis, we executed forward contracts to purchase Canadian dollars at fixed rates of exchange sufficient to make semi-annual payments on the 2006 Debentures. The contracts provide for the purchase of Cdn$1.9 million in April and in October of each year through 2011 at a rate of 1.1075 Canadian dollars per U.S. dollar.

        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.

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        The following table contains the components of recorded foreign exchange (gain) loss for the three months ended March 31, 2010 and 2009:

 
  March 31,
2010
  March 31,
2009
 

Unrealized foreign exchange gains:

             
 

Subordinated notes and convertible debentures

  $ (541 ) $ (12,767 )
 

Forward contracts and other

    (82 )   8,787  
           

    (623 )   (3,980 )

Realized foreign exchange (gains) losses on forward contract settlements

    (1,169 )   557  
           

  $ (1,792 ) $ (3,423 )
           

        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 March 31, 2010:

Convertible debentures

  $ 14,398  

Foreign currency forward contracts

    29,237  
       

  $ 43,635  
       

Interest Rate Risk

        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 90% 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.

        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 $0.6 million.

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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 its 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

        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 March 31, 2010 which are expected to have a material impact on our financial position or results of operations.

ITEM 6.    EXHIBITS.

Exhibit
Number
  Description
 

31.1

 

Certification Pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934

 

31.2

 

Certification Pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934

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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: July 23, 2010

 

Atlantic Power Corporation

 

 

By:

 

/s/ PATRICK J. WELCH

        Name:   Patrick J. Welch
        Title:   Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

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EXHIBIT INDEX

Exhibit
Number
  Description
 

31.1

 

Certification Pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934

 

31.2

 

Certification Pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934

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