2007 Q3 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2007

 

Commission

Registrant; State of Incorporation

IRS Employer

File Number

Address; and Telephone Number

Identification No.

     
     
     

001-09057

WISCONSIN ENERGY CORPORATION

39-1391525

 

(A Wisconsin Corporation)

 
 

231 West Michigan Street

 
 

P.O. Box 1331

 
 

Milwaukee, WI 53201

 
 

(414) 221-2345

 

 

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 [X]    No [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [X]    Accelerated filer [  ]    Non-accelerated filer [  ].

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes [  ]    No [X]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (September 30, 2007):

Common Stock, $.01 Par Value,

116,943,072 shares outstanding.



 

WISCONSIN ENERGY CORPORATION

 
 

                                    

 
     
 

FORM 10-Q REPORT FOR THE QUARTER ENDED SEPTEMBER 30, 2007

 
     
     
     
 

TABLE OF CONTENTS

 

Item

 

Page

     
 

Introduction

8

     
 

Part I -- Financial Information

 
     

1.

Financial Statements

 
     
 

    Consolidated Condensed Income Statements

9

     
 

    Consolidated Condensed Balance Sheets

10

     
 

    Consolidated Condensed Statements of Cash Flows

11

     
 

    Notes to Consolidated Condensed Financial Statements

12

     

2.

Management's Discussion and Analysis of

 
 

    Financial Condition and Results of Operations

24

     

3.

Quantitative and Qualitative Disclosures About Market Risk

44

     

4.

Controls and Procedures

44

     
 

Part II -- Other Information

 
     

1.

Legal Proceedings

45

     

1A.

Risk Factors

45

     

2.

Unregistered Sales of Equity Securities and Use of Proceeds

45

     

6.

Exhibits

47

 

Signatures

48


2

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below.

Wisconsin Energy Subsidiaries and Affiliates

Primary Subsidiaries

Edison Sault

Edison Sault Electric Company

We Power

W.E. Power, LLC

Wisconsin Electric

Wisconsin Electric Power Company

Wisconsin Gas

Wisconsin Gas LLC

Significant Assets

OC 1

Oak Creek expansion Unit 1

OC 2

Oak Creek expansion Unit 2

Point Beach

Point Beach Nuclear Plant

PWGS

Port Washington Generating Station

PWGS 1

Port Washington Generating Station Unit 1

PWGS 2

Port Washington Generating Station Unit 2

Other Affiliates and Subsidiaries

Minergy

Minergy Corp.

Wispark

Wispark LLC

Federal and State Regulatory Agencies

EPA

United States Environmental Protection Agency

FERC

Federal Energy Regulatory Commission

PSCW

Public Service Commission of Wisconsin

SEC

Securities and Exchange Commission

WDNR

Wisconsin Department of Natural Resources

Environmental Terms

BART

Best Available Retrofit Technology

BTA

Best Technology Available

CAIR

Clean Air Interstate Rule

CAVR

Clean Air Visibility Rule

CO2

Carbon Dioxide

NOX

Nitrogen Oxide

PM2.5

Fine Particulate Matter

SO2

Sulfur Dioxide

WPDES

Wisconsin Pollution Discharge Elimination System


3


DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below.

Other Terms and Abbreviations

ALJ

Wisconsin Administrative Law Judge

Compensation Committee

Compensation Committee of the Board of Directors

CPCN

Certificate of Public Convenience and Necessity

Fitch

Fitch Ratings

FPL

FPL Group, Inc.

FTRs

Financial Transmission Rights

Junior Notes

Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067 issued in May 2007

LMP

Locational Marginal Price

MISO

Midwest Independent Transmission System Operator, Inc.

MISO Midwest Market

MISO bid-based energy market

Moody's

Moody's Investor Services

NEIL

Nuclear Electric Insurance Limited

PJM

PJM Interconnection, L.L.C.

PTF

Power the Future

PSEG

Public Service Enterprise Group

RCC

Replacement Capital Covenant dated May 11, 2007

RSG

Revenue Sufficiency Guarantee

S&P

Standard & Poor's Corporation

UI

The United Illuminating Company

Measurements

MW

Megawatt(s) (One MW equals one million watts)

MWh

Megawatt-hour(s)

Accounting Terms

AFUDC

Allowance for Funds Used During Construction

CWIP

Construction Work in Progress

FASB

Financial Accounting Standards Board

FIN

FASB Interpretation

GAAP

Generally Accepted Accounting Principles

OPEB

Other Post-Retirement Employee Benefits

SFAS

Statement of Financial Accounting Standards

Accounting Pronouncements

FIN 46

Consolidation of Variable Interest Entities

FIN 48

Accounting for Uncertainty in Income Taxes

SFAS 109

Accounting for Income Taxes

SFAS 123R

Share-Based Payment (Revised 2004)

SFAS 133

Accounting for Derivative Instruments and Hedging Activities

SFAS 149

Amendment of SFAS 133 on Derivative Instruments and Hedging Activities

SFAS 157

Fair Value Measurements

SFAS 159

The Fair Value Option for Financial Assets and Financial Liabilities


4


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements contained in this report and other documents or oral presentations are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, use of the proceeds from the sale of Point Beach, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" or similar terms or variations of these terms.

Actual results may differ materially from those set forth in forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financial condition include, among others, the following:

Wisconsin Energy Corporation expressly disclaims any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.


7


INTRODUCTION

Wisconsin Energy Corporation is a diversified holding company which conducts its operations primarily in two operating segments: a utility energy segment and a non-utility energy segment. Unless qualified by their context when used in this report, the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries. Our primary subsidiaries are Wisconsin Electric, Wisconsin Gas and We Power.

Utility Energy Segment:   Our utility energy segment consists of: Wisconsin Electric, which serves electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metro Milwaukee, Wisconsin; Wisconsin Gas, which serves gas customers in Wisconsin and water customers in suburban Milwaukee, Wisconsin; and Edison Sault, which serves electric customers in the Upper Peninsula of Michigan. Wisconsin Electric and Wisconsin Gas operate under the trade name of "We Energies".

Sale of Point Beach:   In September 2007, Wisconsin Electric completed the sale of Point Beach to an affiliate of FPL for approximately $924 million. In addition, the buyer assumed certain liabilities related to the plant, including responsibility to decommission Point Beach. Wisconsin Electric intends to use the net gain from the sale and certain decommissioning funds that it retained as a result of the sale to benefit customers, as determined by its regulators. See Note 4 -- Sale of Point Beach in the Notes to Consolidated Condensed Financial Statements in this report.

Non-Utility Energy Segment:   Our non-utility energy segment consists primarily of We Power. We Power was formed in 2001 to design, construct, own and lease to Wisconsin Electric the new generating capacity included in our PTF strategy. See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2006 Annual Report on Form 10-K for more information on PTF.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC. We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with GAAP pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2006 Annual Report on Form 10-K, including the financial statements and notes therein.


8


PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ENERGY CORPORATION

CONSOLIDATED CONDENSED INCOME STATEMENTS

(Unaudited)

Three Months Ended

Nine Months Ended

September 30

September 30

2007

2006

2007

2006

(Millions of Dollars, Except Per Share Amounts)

Operating Revenues

$881.5 

$839.8

$3,089.1 

$2,901.2

Operating Expenses

Fuel and purchased power

254.3 

229.8

716.1 

583.8

Cost of gas sold

78.0 

85.1

710.4 

695.1

Other operation and maintenance

284.3 

287.1

891.5 

875.1

Depreciation, decommissioning

and amortization

85.6 

82.0

250.9 

243.4

Property and revenue taxes

26.2 

24.6

77.5 

73.9

Total Operating Expenses

728.4 

708.6

2,646.4 

2,471.3

Operating Income

153.1 

131.2

442.7 

429.9

Equity in Earnings of Transmission Affiliate

10.9 

9.7

32.1 

28.7

Other Income, Net

14.8 

15.2

47.8 

44.8

Interest Expense

42.5 

41.5

127.2 

129.3

 

Income from Continuing

Operations Before Income Taxes

136.3 

114.6

395.4 

374.1

Income Taxes

53.2 

43.8

153.5 

139.2

Income from Continuing Operations

83.1 

70.8

241.9 

234.9

Income (Loss) from Discontinued

Operations, Net of Tax

(0.2)

-   

(0.6)

4.5

Net Income

$82.9 

$70.8

$241.3 

$239.4

Earnings Per Share (Basic)

Continuing operations

$0.71 

$0.61

$2.07 

$2.01

Discontinued operations

-   

-   

(0.01)

0.04

Total Earnings Per Share (Basic)

$0.71 

$0.61

$2.06 

$2.05

Earnings Per Share (Diluted)

Continuing operations

$0.70 

$0.60

$2.04 

$1.98

Discontinued operations

-   

-   

-   

0.04

Total Earnings Per Share (Diluted)

$0.70 

$0.60

$2.04 

$2.02

Weighted Average Common

Shares Outstanding (Millions)

Basic

116.9 

117.0

116.9 

117.0

Diluted

118.2 

118.4

118.5 

118.3

 

Dividends Per Share of Common Stock

$0.25 

$0.23

$0.75 

$0.69

The accompanying Notes to Consolidated Condensed Financial Statements are an integral part

of these financial statements.


9


WISCONSIN ENERGY CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

September 30, 2007

December 31, 2006

(Millions of Dollars)

Assets

Property, Plant and Equipment

In service

$ 8,734.3 

$ 9,265.4 

Accumulated depreciation

(3,099.1)

(3,423.7)

5,635.2 

5,841.7 

Construction work in progress

1,563.1 

992.4 

Leased facilities, net

83.3 

87.5 

Nuclear fuel, net

-   

130.9 

Net Property, Plant and Equipment

7,281.6 

7,052.5 

Investments

Restricted cash

969.1 

-   

Nuclear decommissioning trust fund

-   

881.6 

Equity investment in transmission affiliate

236.0 

228.5 

Other

35.6 

54.7 

Total Investments

1,240.7 

1,164.8 

Current Assets

Cash and cash equivalents

500.0 

37.0 

Accounts receivable

320.7 

379.3 

Accrued revenues

147.3 

257.8 

Materials, supplies and inventories

410.3 

417.2 

Prepayments and other

100.4 

136.7 

Total Current Assets

1,478.7 

1,228.0 

Deferred Charges and Other Assets

Regulatory assets

1,154.0 

1,091.0 

Goodwill

441.9 

441.9 

Other

165.3 

152.0 

Total Deferred Charges and Other Assets

1,761.2 

1,684.9 

Total Assets

$ 11,762.2 

$ 11,130.2 

Capitalization and Liabilities

Capitalization

Common equity

$ 3,034.6 

$ 2,889.0 

Preferred stock of subsidiary

30.4 

30.4 

Long-term debt

3,493.4 

3,073.4 

Total Capitalization

6,558.4 

5,992.8 

Current Liabilities

Long-term debt due currently

282.3 

296.7 

Short-term debt

831.3 

911.9 

Accounts payable

364.5 

404.5 

Accrued liabilities

482.3 

161.2 

Other

99.1 

113.7 

Total Current Liabilities

2,059.5 

1,888.0 

Deferred Credits and Other Liabilities

Regulatory liabilities

1,854.5 

1,472.1 

Asset retirement obligations

50.0 

371.7 

Deferred income taxes - long-term

242.7 

572.9 

Deferred revenue, net

301.5 

186.2 

Other

695.6 

646.5 

Total Deferred Credits and Other Liabilities

3,144.3 

3,249.4 

Total Capitalization and Liabilities

$ 11,762.2 

$ 11,130.2 

The accompanying Notes to Consolidated Condensed Financial Statements are an integral part

of these financial statements.


10


WISCONSIN ENERGY CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended September 30

2007

2006

(Millions of Dollars)

Operating Activities

Net income

$ 241.3 

$ 239.4 

Reconciliation to cash

Depreciation, decommissioning and amortization

258.2 

250.2 

Nuclear fuel expense amortization

23.2 

22.1 

Equity in earnings of transmission affiliate

(32.1)

(28.7)

Distributions from transmission affiliate

24.7 

22.9 

Deferred income taxes and investment tax credits, net

(22.9)

(25.5)

Deferred revenue

117.4 

53.2 

Change in -

Accounts receivable and accrued revenues

169.1 

285.2 

Inventories

(17.7)

23.9 

Other current assets

36.4 

(4.3)

Accounts payable

(31.4)

(151.3)

Accrued income taxes, net

16.3 

28.7 

Deferred costs, net

(60.5)

(29.4)

Other current liabilities and other

(89.3)

21.9 

Cash Provided by Operating Activities

632.7 

708.3 

Investing Activities

Capital expenditures

(842.2)

(664.0)

Investment in transmission affiliate

-   

(14.6)

Proceeds from asset sales, net

957.6 

69.0 

Proceeds from liquidation of nuclear decommissioning trust

552.4 

-   

Cash designated as restricted cash

(969.1)

-   

Nuclear fuel

(23.8)

(20.4)

Nuclear decommissioning funding

(11.7)

(13.2)

Proceeds from investments within nuclear decommissioning trust

1,528.7 

430.8 

Other activity within nuclear decommissioning trust

(1,528.7)

(430.8)

Other

(49.6)

(7.1)

Cash Used in Investing Activities

(386.4)

(650.3)

Financing Activities

Exercise of stock options

30.6 

12.5 

Purchase of common stock

(55.7)

(21.8)

Dividends paid on common stock

(87.7)

(80.7)

Issuance of long-term debt

523.4 

10.0 

Retirement of long-term debt

(112.8)

(285.3)

Change in short-term debt

(80.6)

253.0 

Other, net

(0.5)

2.3 

Cash Provided by (Used in) Financing Activities

216.7 

(110.0)

Change in Cash and Cash Equivalents

463.0 

(52.0)

Cash and Cash Equivalents at Beginning of Period

37.0 

73.2 

Cash and Cash Equivalents at End of Period

$ 500.0 

$ 21.2 

Supplemental Information - Cash Paid For

Interest (net of amount capitalized)

$ 98.2 

$ 103.3 

Income taxes (net of refunds)

$ 151.0 

$ 139.1 

The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these

financial statements.


11


WISCONSIN ENERGY CORPORATION
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)

 

 1 -- GENERAL INFORMATION

Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8 - Financial Statements and Supplementary Data, in our 2006 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary to a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three and nine months ended September 30, 2007 are not necessarily indicative of the results which may be expected for the entire fiscal year 2007 because of seasonal and other factors.

 

 2 -- NEW ACCOUNTING PRONOUNCEMENTS

Uncertainty in Income Taxes:   In July 2006, the FASB issued FIN 48, an interpretation of SFAS 109. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the enterprise's financial statements in accordance with SFAS 109. As of January 1, 2007, the adoption date for FIN 48, the amount of unrecognized tax benefits was approximately $41.7 million, which included estimated accrued interest and penalties of $5.4 million. The amount of unrecognized tax benefits excludes offsetting FIN 48 related deferred tax assets of $12.5 million. We recognize accrued interest and penalties in the provision for income taxes. The impact of adopting FIN 48 was not material. As of the date of adoption, the net amount of the unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $10.5 million. We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months. Our primary tax jurisdictions include federal and the State of Wisconsin. Currently, the tax years of 2004 through 2006 are subject to federal examination and the tax years of 2002 through 2006 are subject to examination by the State of Wisconsin.

Fair Value Measurements:   In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value to measure assets and liabilities and also defines fair value, provides a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently evaluating the provisions of SFAS 157, and we expect to adopt it on January 1, 2008.

Fair Value Option:   In February 2007, the FASB issued SFAS 159. SFAS 159 permits an entity to measure certain financial assets and financial liabilities at fair value and also establishes presentation and disclosure requirements. SFAS 159 is effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007. We are currently evaluating the provisions of SFAS 159, and we expect to adopt it on January 1, 2008.

 

 3 -- ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS

Background:  As part of our PTF strategy, our non-utility subsidiary, We Power, is building four new generating units (PWGS 1 and 2 and OC 1 and 2) that will be leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the PSCW, our primary regulator. The leases are designed to recover the capital costs of the plant including a return. PWGS 1 was placed in service in July 2005 and is being leased to Wisconsin Electric. Wisconsin Electric will be responsible for all of the operating costs, including fuel, of the PTF units once they are placed in service and we anticipate that we will recover the operating costs of these plants in rates. The accompanying consolidated financial statements eliminate all intercompany transactions between We Power and

12


Wisconsin Electric and reflect the cash inflows from Wisconsin Electric customers and the cash outflows to our vendors and suppliers.

During Construction:  Under the terms of the leases, we collect in current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for the PTF units. Our pre-tax cost of capital is approximately 14%. The carrying costs that we collect in rates are recorded as deferred revenue, and they will be amortized to revenue when the related assets are placed into service. During the construction of the PTF units, we capitalize interest costs at an overall weighted-average pre-tax cost of interest of approximately 6.0%. Capitalized interest is included in the total cost of the PTF units.

Cash Flows:  The following table identifies key pre-tax cash outflows and inflows for the nine months ended September 30, 2007 and 2006 related to the construction of our PTF units as compared to Wisconsin Energy overall.

Capital Expenditures (Millions of Dollars)

Total

PWGS 1

PWGS 2

OC 1

OC 2

PTF

WEC

2007

$     -     

$72.3    

$334.6    

$114.1    

$521.0    

$842.2    

2006

$     -     

$94.7    

$189.9    

$61.2    

$345.8    

$664.0    

Capitalized Interest (Millions of Dollars)

Total

PWGS 1

PWGS 2

OC 1

OC 2

PTF

WEC

2007

$     -     

$11.0     

$30.1     

$9.6     

$50.7     

$52.0     

2006

$     -     

$5.5     

$12.8     

$4.6     

$22.9     

$27.1     

Deferred Revenue, net (Millions of Dollars)

Total

PWGS 1

PWGS 2

OC 1

OC 2

PTF

WEC

2007

$     -     

$24.8     

$69.9     

$22.7     

$117.4     

$117.4     

2006

$     -     

$12.6     

$29.9     

$10.7     

$53.2     

$53.2     

 

Balance Sheet:   As noted above, we collect in current rates carrying costs that are calculated based on the cash expenditures included in CWIP multiplied by our pre-tax cost of capital. The carrying costs are recorded as deferred revenue. Our total CWIP balance includes cash expenditures, capitalized interest and accruals. The following table identifies key amounts related to our PTF units that are recorded on our balance sheet as of September 30, 2007 and December 31, 2006:


13

CWIP - Cash Expenditures (Millions of Dollars)

Total

As of

PWGS 1

PWGS 2

OC 1

OC 2

PTF

September 30, 2007

$     -    

$262.4    

$811.2    

$273.8    

$1,347.4    

December 31, 2006

$     -    

$196.2    

$487.7    

$152.6    

$836.5    

Total CWIP (Millions of Dollars)

Total

As of

PWGS 1

PWGS 2

OC 1

OC 2

PTF

WEC

September 30, 2007

$     -    

$284.9    

$870.9    

$294.4    

$1,450.2    

$1,563.1    

December 31, 2006

$     -    

$207.7    

$517.3    

$163.5    

$888.5    

$992.4    

Net Plant in Service (Millions of Dollars)

Total

As of

PWGS 1

PWGS 2

OC 1

OC 2

PTF

WEC

September 30, 2007

$344.4   

$     -    

$     -    

$     -    

$344.4   

$5,635.2   

December 31, 2006

$350.1   

$     -    

$     -    

$     -    

$350.1   

$5,841.7   

Deferred Revenue (Millions of Dollars)

Total

As of

PWGS 1

PWGS 2

OC 1

OC 2

PTF

WEC

September 30, 2007

$66.2    

$52.4    

$135.9    

$47.0    

$301.5    

$301.5    

December 31, 2006

$68.3    

$27.5    

$66.0    

$24.4    

$186.2    

$186.2    

 

Income Statement:   Once the PTF units are placed in service, we expect to recover in rates the lease costs which reflect the authorized cash construction costs of the units plus a return. The authorized cash costs are established by the PSCW. The authorized cash costs exclude capitalized interest because carrying costs are recovered during the construction of the units. The lease payments are expected to be levelized, except that OC 1 and OC 2 will be recovered on a levelized basis that has a one time 10.6% escalation after the first five years of the leases. The leases establish a set return on equity component of 12.7% after tax. The interest component of the return is determined up to 180 days prior to the date that the units are placed in service.

We recognize revenues related to the lease payments that are included in our rates. In addition, our revenues will include the amortization of the deferred revenues that reflect the carrying costs that are collected during construction. The deferred revenue will be amortized on a straight line basis over the lease term. We will depreciate the units on a straight line basis over their expected service life.

In July 2005, PWGS 1 was placed in service. This asset had a cost of approximately $364.3 million, which included approximately $31.1 million of capitalized interest. The asset is being depreciated over its estimated useful life of approximately 37 years. The cost of this asset, plus a return, is expected to be recovered through Wisconsin Electric's rates over a 25 year period at an annual amount of approximately $48 million.

 

 4 -- SALE OF POINT BEACH

On September 28, 2007, Wisconsin Electric sold Point Beach to an affiliate of FPL for approximately $924 million. Pursuant to the terms of the sale agreement, the buyer purchased Point Beach, its nuclear fuel and associated inventories and assumed the obligation to decommission the plant. Wisconsin Electric retained approximately $486 million of the sales proceeds, which represents the net book value of the assets sold and certain transaction costs. In addition, Wisconsin Electric has deferred the net gain on the sale of approximately $400 million as a regulatory liability and has deposited those proceeds in a restricted cash account.

In connection with the sale, Wisconsin Electric also transferred $390 million of decommissioning funds to the buyer. Wisconsin Electric then liquidated the balance of the decommissioning trust assets and


14


retained approximately $552 million of that cash. This cash was also placed in the restricted cash account. We intend to use the cash in the restricted cash account and the interest earned on the balance, for the benefit of our customers and to pay certain taxes related to the liquidation of the qualified decommissioning trust. Our regulators will decide the manner in which these proceeds will benefit customers in future rate proceedings. For further information on the 2008 Rate Case, see Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources - Utility Rates and Regulatory Matters in this report.

A long-term power purchase agreement with the buyer became effective upon closing of the sale pursuant to which Wisconsin Electric will purchase all of the existing energy and capacity of Point Beach. The power purchase agreement extends through 2030 for Unit 1 and 2033 for Unit 2. Based on the agreement, we will be paying the buyer a price per MWh for energy delivered according to a schedule that is established in the agreement. Under the agreement, if our credit rating and the credit rating of Wisconsin Electric from either S&P or Moody's fall below investment grade, or if the holders of any indebtedness in excess of $100 million accelerate or have the right to accelerate the maturity of such indebtedness as a result of a default, we would need to provide collateral in the amount of $100 million (escalating at 3% per year commencing in 2024).

Wisconsin Electric maintains insurance with NEIL through which it can recover up to $1.0 million per week, subject to a total limit of $24.5 million, during any prolonged outage at Point Beach caused by accidental property damage which results in Wisconsin Electric's inability to receive power under its power purchase agreement with the new owner of Point Beach. Under policies issued by NEIL, the insured member may be liable for a retrospective premium in the event of catastrophic losses exceeding the full financial resources of NEIL. Wisconsin Electric's maximum retrospective liability under this policy is $2.6 million.

 

 5 -- ASSET RETIREMENT OBLIGATIONS

The following table presents the change in our asset retirement obligations as of September 30, 2007.

 

Balance at
12/31/06

Liabilities
Incurred

Liabilities
Settled


Accretion

Cash Flow
Revisions

Balance at
9/30/07

 

(Millions of Dollars)

Asset Retirement Obligations


$371.7     


$  -     


($338.4)    


$14.3     


$2.4    


$50.0     

Our asset retirement obligations were significantly reduced due to the sale of Point Beach. Upon closing of the sale, the buyer assumed the liability to decommission the plant, including the asset retirement obligation, spent fuel and other requirements to return the site to greenfield status.

 

 6 -- COMMON EQUITY

Share-Based Compensation Expense:   For a description of share-based compensation, including stock options, restricted stock and performance units, see Note J -- Common Equity in our 2006 Annual Report on Form 10-K. Effective January 1, 2006, we adopted SFAS 123R using the modified prospective method. We utilize the straight-line attribution method for recognizing share-based compensation expense under SFAS 123R. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. There were no modifications to outstanding stock options during the period. Shares purchased on the open market are currently used to satisfy share-based awards.



15


The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors.

   

Three Months Ended
September 30

 

Nine Months Ended
September 30

   

2007

 

2006

 

2007

 

2006

   

(Millions of Dollars)

                 

  Stock options

 

$2.4  

 

$1.9  

 

$9.6  

 

$5.7  

  Performance units

 

1.0  

 

1.8  

 

2.4  

 

4.5  

  Restricted stock

 

0.3  

 

0.3  

 

0.8  

 

0.9  

  Share-based compensation expense

$3.7  

$4.0  

$12.8  

$11.1  

Related Tax Benefit

$1.4  

$1.7  

$5.1  

$4.5  

Stock Option Activity:   During the first nine months of 2007, the Compensation Committee granted 1,371,590 options that had an estimated fair value of $8.72 per share. During the first nine months of 2006, the Compensation Committee granted 1,304,275 options that had an estimated fair value of $7.55 per share. The following assumptions were used to value the options using a binomial option pricing model:

   

2007

 

2006

         

Risk free interest rate

 

4.7% - 5.1%

 

4.3% - 4.4%

Dividend yield

 

2.2%

 

2.4%

Expected volatility

 

13.0% - 20.0%

 

17.0% - 20.0%

Expected forfeiture rate

 

2.0%

 

2.0%

Expected life (years)

 

6.0   

 

6.3   

The risk-free interest rate is based on the U.S. Treasury interest rate whose term is consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate and expected life assumptions are based on our historical experience.

The following is a summary of our stock option activity through the three and nine months ended September 30, 2007.

Stock Options

 

Number of Options

 

Weighted-Average Exercise Price

 

Weighted-Average Remaining Contractual Life (Years)

 

Aggregate Intrinsic Value (Millions)

 

Outstanding as of July 1, 2007

 

7,945,432  

 

$33.98    

         

   Granted

 

-      

 

-      

         

   Exercised

 

(23,147) 

 

$23.53    

         

   Forfeited

 

-      

 

-      

         

Outstanding as of September 30, 2007

 

7,922,285  

 

$34.01    

         

Outstanding as of January 1, 2007

 

7,721,826  

 

$30.52    

         

   Granted

 

1,371,590  

 

$47.76    

         

   Exercised

 

(1,160,167) 

 

$27.03    

         

   Forfeited

 

(10,964) 

 

$35.66    

         

Outstanding as of September 30, 2007

 

7,922,285  

 

$34.01    

 

6.6

 

$91.0

 

Exercisable as of September 30, 2007

4,448,005  

$28.85    

5.3

$72.4




16


The intrinsic value of options exercised was $0.5 million and $24.7 million for the three and nine months ended September 30, 2007, and $3.8 million and $9.4 million for the same periods in 2006, respectively. Cash received from options exercised was $30.6 million and $12.5 million for the nine months ended September 30, 2007 and 2006, respectively. The related tax benefit for the same periods was approximately $9.1 million and $3.7 million, respectively.

The following table summarizes information about our non-vested options during the three and nine months ended September 30, 2007:

   

Three Months

 

Nine Months

       

Weighted

     

Weighted-

Non-Vested Stock Options

 

Number of Options

 

Average
Fair Value

 

Number of Options

 

Average
Fair Value

                 

Non-vested - Beginning of Period

 

3,474,280  

 

$8.21  

 

2,587,849  

 

$7.94   

   Granted

 

-     

 

-   

 

1,371,590  

 

$8.72   

   Vested

 

-     

 

-   

 

(477,995) 

 

$8.22   

   Forfeited

 

-     

 

-   

 

(7,164) 

 

$8.18   

Non-vested as of September 30, 2007

 

3,474,280  

 

$8.21   

 

3,474,280  

 

$8.21   

As of September 30, 2007, total compensation costs related to non-vested stock options not yet recognized was approximately $10.7 million, which is expected to be recognized over the next 21 months on a weighted-average basis.

The following table summarizes information about stock options outstanding as of September 30, 2007:

Options Outstanding

Options Exercisable

Weighted-Average

Weighted-Average

Range of Exercise Prices

Number of Options

Exercise Price

Remaining Contractual Life (Years)

Number of Options

Exercise Price

Remaining Contractual Life (Years)

$12.79  to  $23.05

1,133,389   

$21.51   

3.6

1,133,389   

$21.51   

3.6

$25.31  to  $31.07

1,559,247   

$27.03   

4.9

1,559,247   

$27.03   

4.9

$33.44  to  $47.76

5,229,649   

$38.80   

7.8

1,755,369   

$35.20   

6.7

7,922,285   

$34.01   

6.6

4,448,005   

$28.85   

5.3

Restricted Shares:   The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during the three and nine months ended September 30, 2007:

   

Three Months

 

Nine Months

Restricted Shares

 

Number of shares

 

Weighted-Average Grant Date Fair Value

 

Number of shares

 

Weighted-Average Grant Date Fair Value

                 

Outstanding - Beginning of Period

 

155,003  

     

184,665   

   

   Granted

 

-       

 

    -      

 

14,139   

 

$47.19     

   Released / Forfeited

 

(6,033) 

 

$29.26  

 

(49,834)  

 

$27.06     

Outstanding as of September 30, 2007

 

148,970  

     

148,970   

   

We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards. The intrinsic value of restricted stock vesting


17


was $0.2 million and $2.7 million for the three and nine months ended September 30, 2007, respectively. The intrinsic value for the same periods in 2006 was $0.1 million and $0.4 million, respectively. The related tax benefit was zero and $0.9 million for the three and nine months ended September 30, 2007, respectively, and $0.1 million and $0.2 million for the same periods in 2006.

As of September 30, 2007, total compensation cost related to restricted stock not yet recognized was approximately $2.5 million, which is expected to be recognized over the next 44 months on a weighted-average basis.

Performance Units:   In January 2007 and 2006, the Compensation Committee granted 136,905 and 150,821 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units that will be awarded is dependent upon the achievement of certain financial performance of our stock over a three year period. We are accruing compensation costs over the three year period based on our estimate of the final expected value of the award. Performance units vesting were approximately $0.9 million, with a related tax benefit of $0.3 million, during the nine months ended September 30, 2007. Performance shares earned as of December 31, 2006, vested and were distributed during the first quarter of 2007 and had a total intrinsic value of $7.2 million. The tax benefit realized due to the distribution of performance shares was approximately $2.1 million. As of September 30, 2007, total compensation cost related to performance units not yet recognized was approximately $6.7 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Restrictions:   Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from its principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our principal utility subsidiaries to transfer funds to us in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. See Note J --Common Equity in our 2006 Annual Report on Form 10-K for additional information on these restrictions.

We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

Comprehensive Income:   Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners. We recorded the following total comprehensive income during the nine months ended September 30:

Comprehensive Income

2007

2006

(Millions of Dollars)

         

Net Income

 

$241.3    

 

$239.4    

Other Comprehensive Income

       

  Hedging

 

0.3    

 

0.3    

Total Other Comprehensive Income

 

0.3    

 

0.3    

Total Comprehensive Income

 

$241.6    

 

$239.7    


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 7 -- LONG-TERM DEBT

Wisconsin Electric had a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust, which was treated as a capital lease. Under this arrangement, Wisconsin Electric leased and amortized nuclear fuel to fuel expense as power was generated. In connection with the sale of Point Beach, the nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust was dissolved in September 2007. Wisconsin Electric terminated the lease and paid off all of Wisconsin Electric Fuel Trust's outstanding commercial paper, aggregating $76.2 million.

In May 2007, we issued $500 million of Junior Notes. Due to certain features of the Junior Notes, rating agencies consider them to be hybrid instruments with a combination of debt and equity characteristics. The Junior Notes bear interest at 6.25% per year until May 15, 2017. Beginning May 15, 2017, the Junior Notes bear interest at the three-month London Interbank Offered Rate (LIBOR) plus 2.1125%, reset quarterly. The proceeds from this issuance were used to repay short-term debt incurred to both fund PTF and for other working capital purposes.

In connection with the issuance of the Junior Notes, we executed the RCC for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been initially designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.

 

 8 -- DERIVATIVE INSTRUMENTS

We follow SFAS 133, as amended by SFAS 149, effective July 1, 2003, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of September 30, 2007, we recognized $14.9 million in regulatory assets and $1.6 million in regulatory liabilities related to derivatives.


19


 9 -- BENEFITS

The components of our net periodic pension and OPEB costs for the three and nine months ended September 30, 2007 and 2006 were as follows:


Pension Benefits

OPEB

   

2007

 

2006

 

2007

 

2006

   

(Millions of Dollars)

Three Months Ended September 30

               

Net Periodic Benefit Cost

               

    Service cost

 

$7.5   

 

$8.4   

 

$2.9   

 

$3.1   

    Interest cost

 

17.8   

 

17.3   

 

4.8   

 

4.4   

    Expected return on plan assets

 

(21.2)  

 

(20.2)  

 

(3.8)  

 

(3.7)  

Amortization of:

               

    Transition obligation

 

-     

 

-     

 

-     

 

0.1   

    Prior service cost (credit)

 

1.4   

 

1.4   

 

(3.3)  

 

(3.3)  

    Actuarial loss

 

3.9   

 

5.9   

 

1.8   

 

2.2   

Net Periodic Benefit Cost

$9.4   

$12.8   

$2.4   

$2.8   


Pension Benefits

OPEB

   

2007

 

2006

 

2007

 

2006

   

(Millions of Dollars)

Nine Months Ended September 30

               

Net Periodic Benefit Cost

               

    Service cost

 

$22.6   

 

$25.4   

 

$8.7   

 

$9.3   

    Interest cost

 

53.6   

 

52.2   

 

14.4   

 

13.4   

    Expected return on plan assets

 

(63.4)  

 

(61.2)  

 

(11.4)  

 

(11.2)  

Amortization of:

               

    Transition obligation

 

-    

 

-     

 

0.2   

 

0.3  

    Prior service cost (credit)

 

4.3   

 

4.1   

 

(10.0)  

 

(10.1)  

    Actuarial loss

 

12.9   

 

17.6   

 

5.5   

 

6.6   

Net Periodic Benefit Cost

 

$30.0   

 

$38.1   

 

$7.4   

 

$8.3   

 

 10 -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of September 30, 2007, we had the following guarantees:

Maximum Potential Future Payments

Outstanding as of
September 30, 2007

Liability Recorded
as of September 30, 2007

(Millions of Dollars)

Wisconsin Energy

    Non-Utility Energy

$   -     

$   -      

$   -      

    Other

2.5    

2.5    

-      

Wisconsin Electric

2.8    

0.1    

-      

Subsidiary

6.1    

6.1    

0.9     

  Total

11.4    

8.7    

0.9     

A non-utility energy segment guarantee in support of Wisvest-Connecticut, which we sold in December 2002 to PSEG, provides financial assurance for potential obligations relating to environmental


20


remediation under the original purchase agreement for Wisvest-Connecticut with UI. The potential obligations for environmental remediation, which are unlimited, are reimbursable by PSEG under the terms of the sale agreement in the event that we are required to perform under the guarantee.

Other guarantees support obligations of our affiliates to third parties under loan agreements and surety bonds. In the event our affiliates fail to perform, we would be responsible for the obligations.

Wisconsin Electric guarantees the potential retrospective premiums that could be assessed under Wisconsin Electric's nuclear insurance program (see Note 4 -- Sale of Point Beach in this report).

Subsidiary guarantees support loan obligations and surety bonds between our affiliates and third parties. In the event our affiliates fail to perform, our subsidiary would be responsible for the obligations.

Postemployment benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability, excluding severance benefits, for such benefits was $13.5 million as of September 30, 2007 and $13.0 million as of December 31, 2006.

 

 11 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable operating segments for the three and nine months ended September 30, 2007 and 2006 is shown in the following table.

   

Reportable Operating Segments

       
           

Corporate &

   
   

Energy     

 

Other (a)

   
           

Reconciling

 

Total

Wisconsin Energy Corporation

 

Utility

 

Non-Utility

 

Items (c)

 

Consolidated

   

(Millions of Dollars)

Three Months Ended

               
                 

September 30, 2007

               

  Operating Revenues (b)

 

$872.0  

 

$21.1  

 

($11.6) 

 

$881.5  

  Operating Income

$136.9  

$13.5  

$2.7  

$153.1  

  Interest Expense

 

$29.2  

 

$1.8  

 

$11.5  

 

$42.5  

  Income Tax Expense (Benefit)

 

$52.4  

 

$4.7  

 

($3.9) 

 

$53.2  

  Loss from Discontinued Operations, net

 

$   -     

 

$   -     

 

($0.2) 

 

($0.2) 

  Net Income (Loss)

 

$80.6  

 

$7.2  

 

($4.9) 

 

$82.9  

  Capital Expenditures

 

$98.9  

 

$170.7  

 

$0.1  

 

$269.7  

                 

September 30, 2006

               

  Operating Revenues (b)

 

$835.7  

 

$20.6  

 

($16.5) 

 

$839.8  

  Operating Income (Loss)

 

$121.6  

 

$12.9  

 

($3.3) 

 

$131.2  

  Interest Expense

 

$25.6  

 

$3.6  

 

$12.3  

 

$41.5  

  Income Tax Expense (Benefit)

 

$46.4  

 

$4.0  

 

($6.6) 

 

$43.8  

  Net Income (Loss)

 

$72.7  

 

$6.5  

 

($8.4) 

 

$70.8  

  Capital Expenditures

 

$104.0  

 

$139.0  

 

$0.1  

 

$243.1  

                 


21


   

Reportable Operating Segments

       
           

Corporate &

   
   

Energy     

 

Other (a)

   
           

Reconciling

 

Total

Wisconsin Energy Corporation

 

Utility

 

Non-Utility

 

Items (c)

 

Consolidated

   

(Millions of Dollars)

Nine Months Ended

               
                 

September 30, 2007

               

  Operating Revenues (b)

 

$3,076.4  

 

$56.7  

 

($44.0) 

 

$3,089.1  

  Operating Income (Loss)

$409.1  

$34.3  

($0.7) 

$442.7  

  Interest Expense

 

$86.4  

 

$5.6  

 

$35.2  

 

$127.2  

  Income Tax Expense (Benefit)

 

$156.0  

 

$11.2  

 

($13.7) 

 

$153.5  

  Loss from Discontinued Operations, net

 

$   -     

 

$   -    

 

($0.6) 

 

($0.6) 

  Net Income (Loss)

 

$241.9  

 

$17.8  

 

($18.4) 

 

$241.3  

  Capital Expenditures

 

$316.2  

 

$524.1  

 

$1.9  

 

$842.2  

  Total Assets

 

$10,292.7  

 

$1,807.4  

 

($337.9) 

 

$11,762.2  

                 

September 30, 2006

               

  Operating Revenues (b)

 

$2,895.2  

 

$55.0  

 

($49.0) 

 

$2,901.2  

  Operating Income (Loss)

$405.7  

$33.5  

($9.3) 

$429.9  

  Interest Expense

 

$80.2  

 

$11.5  

 

$37.6  

 

$129.3  

  Income Tax Expense (Benefit)

 

$149.4  

 

$9.8  

 

($20.0) 

 

$139.2  

  Income from Discontinued Operations, net

 

$   -     

 

$   -    

 

$4.5  

 

$4.5  

  Net Income (Loss)

 

$241.9  

 

$13.7  

 

($16.2) 

 

$239.4  

  Capital Expenditures

 

$317.1  

 

$346.8  

 

$0.1  

 

$664.0  

  Total Assets

 

$9,538.9  

 

$1,130.1  

 

($44.8) 

 

$10,624.2  

                 

(a)

Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark and non-utility investment in renewable energy and recycling technology by Minergy, as well as interest on corporate debt.

   

(b)

An elimination for intersegment revenues is included in Operating Revenues of $17.2 million and $16.7 million for the three months ended September 30, 2007 and 2006, respectively, and $51.4 million and $49.8 million for the nine months ended September 30, 2007 and 2006, respectively.

   

(c)

An elimination for the PWGS 1 lease between We Power and Wisconsin Electric is included in Total Assets of $307.5 million and $319.3 million at September 30, 2007 and 2006, respectively.

 

 12 -- COMMITMENTS AND CONTINGENCIES

EPA - Consent Decree:   In April 2003, Wisconsin Electric and the EPA announced that a consent decree had been reached that resolved all issues related to a request for information that had been issued by the EPA. In July 2003, the consent decree was amended to include the State of Michigan. Under the consent decree, Wisconsin Electric agreed to significantly reduce its air emissions from its coal-fired generating facilities. The reductions are expected to be achieved by 2013 through a combination of installing new pollution control equipment, upgrading existing equipment and retiring certain older units. Through September 30, 2007, we have spent approximately $371.0 million associated with implementing the EPA agreement. The total cost of implementing this agreement is estimated to be $1.0 billion through the year 2013. The U.S. District Court for the Eastern District of Wisconsin approved the amended consent decree and entered it in October 2007. Interveners in the case have the right to appeal the court's decision to the federal court of appeals.


22


Environmental Matters:   We periodically review our exposure for remediation costs as evidence becomes available indicating that our remediation liability has changed. Based on current information, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

Divestitures:   Over the past several years, we have sold various businesses and assets, including Point Beach. In connection with these sales, we have agreed to provide the respective buyers with customary indemnification provisions including, but not limited to, certain environmental, asbestos and product liability matters. We have established reserves as deemed appropriate for these indemnification provisions.


23


ITEM 2.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
                 AND RESULTS OF OPERATIONS

 

RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 2007

CONSOLIDATED EARNINGS

The following table compares our net income during the third quarter of 2007 with the third quarter of 2006 including favorable (better (B)) or unfavorable (worse (W)) variances.

Three Months Ended September 30

2007

B (W)

2006

(Millions of Dollars)

Operating Income by Segment

Utility Energy

$136.9    

$15.3    

$121.6    

Non-Utility Energy

13.5    

0.6    

12.9    

Corporate and Other

2.7    

6.0    

(3.3)   

  Total Operating Income

153.1    

21.9    

131.2    

Equity in Earnings of Transmission Affiliate

10.9    

1.2    

9.7    

Other Income, Net

14.8    

(0.4)   

15.2    

Interest Expense

42.5    

(1.0)   

41.5    

Income From Continuing Operations Before Income Taxes

136.3    

21.7    

114.6    

Income Taxes

53.2    

(9.4)   

43.8    

  Income From Continuing Operations

83.1    

12.3    

70.8    

  Loss From Discontinued Operations, Net of Tax

(0.2)   

(0.2)   

-    

Net Income

$82.9    

$12.1    

$70.8    

Diluted Earnings Per Share

   Continuing Operations

$0.70    

$0.10    

$0.60    

   Discontinued Operations

    -      

   -      

    -      

Total Diluted Earnings Per Share

$0.70    

$0.10    

$0.60    



 

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $136.9 million of operating income during the third quarter of 2007, an increase of $15.3 million, or 12.6%, compared with the third quarter of 2006. The following table summarizes the operating income of this segment between the comparative quarters.



24



 

Three Months Ended September 30

Utility Energy Segment

 

2007

 

B (W)

 

2006

   

(Millions of Dollars)

Operating Revenues

  Electric

 

$732.6    

 

$43.5    

 

$689.1    

  Gas

 

133.4    

 

(7.8)   

 

141.2    

  Other

 

6.0    

 

0.6    

 

5.4    

Total Operating Revenues

 

872.0    

 

36.3    

 

835.7    

Fuel and Purchased Power

 

255.4    

 

(24.6)   

 

230.8    

Cost of Gas Sold

 

78.0    

 

7.1    

 

85.1    

    Gross Margin

 

538.6    

 

18.8    

 

519.8    

Other Operating Expenses

           

  Other Operation and Maintenance

 

293.3    

 

1.6    

 

294.9    

  Depreciation, Decommissioning

           

    and Amortization

 

82.4    

 

(3.5)   

 

78.9    

  Property and Revenue Taxes

 

26.0    

 

(1.6)   

 

24.4    

Operating Income

 

$136.9    

 

$15.3    

 

$121.6    

During September 2007, we completed the sale of Point Beach. In connection with the sale, a power purchase agreement with an affiliate of FPL became effective to purchase all of the existing energy and capacity produced by Point Beach. As a result of the sale and the power purchase agreement, we expect future income statements to look different than historical income statements. Prospectively, we expect to see significantly higher purchased power expense because we will be purchasing energy from the new owner of Point Beach. We also expect to see a reduction of other operation and maintenance costs, as well as lower depreciation, decommissioning and amortization costs because we no longer own Point Beach. Finally, under the power purchase agreement, we will pay higher amounts per MWh for purchased power in the summer months and lower amounts in the non-summer months.



Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the third quarter of 2007 with the third quarter of 2006.

   

Three Months Ended September 30

   

Electric Revenues

 

MWh Sales

   

2007

 

B (W)

 

2006

 

2007

 

B (W)

 

2006

   

(Millions of Dollars)

 

(Thousands)

Customer Class

                       

  Residential

 

$254.4   

 

$8.2   

 

$246.2   

 

2,363.7   

 

23.5   

 

2,340.2   

  Small Commercial/Industrial

230.8   

9.0   

221.8   

2,546.7   

39.8   

2,506.9   

  Large Commercial/Industrial

177.8   

7.1   

170.7   

2,985.9   

59.0   

2,926.9   

  Other-Retail

 

4.6   

 

0.1   

 

4.5   

 

39.3   

 

(0.3)  

 

39.6   

    Total Retail Sales

 

667.6   

 

24.4   

 

643.2   

 

7,935.6   

 

122.0   

 

7,813.6   

  Wholesale-Other

 

25.1   

 

3.8   

 

21.3   

 

550.2   

 

33.8   

 

516.4   

  Resale-Utilities

 

28.3   

 

14.8   

 

13.5   

 

390.7   

 

198.5   

 

192.2   

  Other Operating Revenues

11.6   

0.5   

11.1   

-      

-       

-      

Total

$732.6   

$43.5   

$689.1   

8,876.5   

354.3   

8,522.2   

Weather -- Degree Days (a)

                       

  Cooling (531 Normal)

             

567   

 

(10)  

 

577   

(a)

As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.




25


During the third quarter of 2007, total electric utility operating revenues increased by $43.5 million, or 6.3%, when compared with the third quarter of 2006. The two biggest drivers of the increase were revenues attributable to fuel and purchased power of approximately $14.6 million, and increased revenues related to Resale-Utilities of approximately $14.8 million. Our policy for electric fuel revenues is to not recognize revenue for any currently billable amounts if it is probable that we will refund those amounts to customers. In 2006, we experienced lower than expected fuel and purchased power costs, and we established $14.6 million of reserves to reflect amounts that we expected to refund to customers. No such reserves have been established in 2007, as we are experiencing higher fuel and purchased power costs. The increase in Resale-Utilities reflects our ability to sell electricity into the MISO and PJM markets due to increased availability of our base-load plants.

Total electric MWh sales volumes increased by 354.3 thousand MWh, or 4.2%, in the third quarter of 2007 compared with the same period in 2006. The largest increase came from sales to other utilities, as discussed above. Our retail sales increased by 1.6%, as compared to the same period last year. For the quarter, the weather, as measured by cooling degree days, was slightly warmer than normal and slightly cooler than the same period in 2006.

 

Fuel and Purchased Power

Our fuel and purchased power costs increased by $24.6 million, or 10.7%, when compared to the third quarter of 2006. As noted above, our total electric sales volume increased by approximately 4.2% in the quarter; however, our average fuel and purchased power cost per MWh increased by $1.72 or approximately 6.8%. The higher cost per MWh was due to an 8.3% increase in the cost of coal and coal transportation contracts between periods. In addition, we experienced higher utilization in our gas generation and purchased energy in the quarter ended September 30, 2007, as compared to the same period in 2006. This generation was primarily related to the increased revenue related to Resale-Utilities.

 

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the third quarter of 2007 with the third quarter of 2006. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas margins decreased by $0.7 million, or 1.2%.

Three Months Ended September 30

2007

B (W)

2006

(Millions of Dollars)

Gas Operating Revenues

$133.4   

($7.8)  

$141.2   

Cost of Gas Sold

78.0   

7.1   

85.1   

Gross Margin

$55.4   

($0.7)  

$56.1   

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2007 with the third quarter of 2006.


26


Three Months Ended September 30

Gross Margin

Therm Deliveries

2007

B (W)

2006

2007

B (W)

2006

(Millions of Dollars)

(Millions)

Customer Class

  Residential

$33.0   

($0.5)  

$33.5   

47.4   

(3.2)  

50.6   

  Commercial/Industrial

9.4   

(0.5)  

9.9   

33.2   

(1.6)  

34.8   

  Interruptible

0.4   

-    

0.4   

4.4   

0.5   

3.9   

    Total Retail Gas Sales

42.8   

(1.0)  

43.8   

85.0   

(4.3)  

89.3   

  Transported Gas

11.2   

0.1   

11.1   

201.3   

0.5   

200.8   

  Other

1.4   

0.2   

1.2   

-      

-      

-      

Total

$55.4   

($0.7)  

$56.1   

286.3   

(3.8)  

290.1   

Weather -- Degree Days (a)

  Heating (132 Normal)

108   

(20)   

128   

(a)

As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

The decrease in gross margin was primarily related to mild weather in the third quarter of 2007 compared to the third quarter of 2006. As measured by heating degree days, the third quarter of 2007 was 15.6% warmer than the third quarter of 2006 and 18.2% warmer than normal.



CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

Corporate and other affiliates had operating income of $2.7 million during the third quarter of 2007 as compared to an operating loss of $3.3 million in the same period during 2006. The increase is primarily related to our Wispark operations, which had operating income during the third quarter of 2007 and operating losses in the third quarter of 2006.

 

CONSOLIDATED OTHER INCOME, NET

Other income, net decreased by $0.4 million, or 2.6%, when compared to the third quarter of 2006. The reduction primarily reflects a decrease in AFUDC of $3.2 million in connection with the new scrubber we put in service at our Pleasant Prairie Power Plant during the fourth quarter of 2006. This scrubber was installed as part of our EPA consent decree spending. For further information on the consent decree with the EPA, see Note 12 -- Commitments and Contingencies in the Notes to Consolidated Condensed Financial Statements in this report, as well as Note S -- Commitments and Contingencies in our 2006 Annual Report on Form 10-K. This reduction was offset, in part, by an increase of approximately $2.9 million related to gains on additional land sold in Northern Wisconsin and the Upper Peninsula of Michigan and capitalized carrying costs.

 

CONSOLIDATED INTEREST EXPENSE

Three Months Ended September 30

Interest Expense

2007

2006

(Millions of Dollars)

Gross Interest Costs

$62.9   

$52.5   

Less: Capitalized Interest

20.4   

11.0   

Interest Expense

$42.5   

$41.5   



27


Our gross interest costs increased by $10.4 million, or 19.8%, when compared to the third quarter of 2006 due to increased debt levels as a result of our PTF construction program. However, in connection with the PTF construction program we capitalize interest during construction. Our capitalized interest increased by $9.4 million due to higher levels of construction in progress at our PTF plants. As a result, our net interest expense increased $1.0 million for the quarter ended September 30, 2007 when compared to the same period in 2006.

 

CONSOLIDATED INCOME TAXES

For the third quarter of 2007, our effective tax rate applicable to continuing operations was 39.0% compared to 38.2% for the third quarter of 2006. We expect our 2007 annual effective tax rate to be between 38% and 39%.

 

 

RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2007


CONSOLIDATED EARNINGS

The following table compares our net income during the first nine months of 2007 with the first nine months of 2006 including favorable (better (B)) or unfavorable (worse (W)) variances.

Nine Months Ended September 30

2007

B (W)

2006

(Millions of Dollars)

Operating Income by Segment

Utility Energy

$409.1    

$3.4   

$405.7    

Non-Utility Energy

34.3    

0.8    

33.5    

Corporate and Other

(0.7)   

8.6    

(9.3)   

  Total Operating Income

442.7    

12.8    

429.9    

Equity in Earnings of Transmission Affiliate

32.1    

3.4    

28.7    

Other Income, Net

47.8    

3.0    

44.8    

Interest Expense

127.2    

2.1    

129.3    

Income From Continuing Operations Before Income Taxes

395.4    

21.3    

374.1    

Income Taxes

153.5    

(14.3)   

139.2    

  Income From Continuing Operations

241.9    

7.0    

234.9    

  Income (Loss) From Discontinued Operations, Net of Tax

(0.6)    

(5.1)   

4.5    

Net Income

$241.3    

$1.9    

$239.4    

Diluted Earnings Per Share

   Continuing Operations

$2.04    

$0.06    

$1.98    

   Discontinued Operations

      -    

(0.04)   

0.04    

Total Diluted Earnings Per Share

$2.04    

$0.02    

$2.02    

 

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $409.1 million of operating income during the first nine months of 2007, an increase of $3.4 million, or 0.8%, compared with the first nine months of 2006. The following table summarizes the operating income of this segment between the comparative periods.


28


   

Nine Months Ended September 30

Utility Energy Segment

 

2007

 

B (W)

 

2006

   

(Millions of Dollars)

Operating Revenues

  Electric

 

$2,037.5    

 

$136.5    

 

$1,901.0    

  Gas

 

1,011.8    

 

38.7    

 

973.1    

  Other

 

27.1    

 

6.0    

 

21.1    

Total Operating Revenues

 

3,076.4    

 

181.2    

 

2,895.2    

Fuel and Purchased Power

 

719.2    

 

(132.3)   

 

586.9    

Cost of Gas Sold

 

710.4    

 

(15.3)   

 

695.1    

    Gross Margin

 

1,646.8    

 

33.6    

 

1,613.2    

Other Operating Expenses

           

  Other Operation and Maintenance

 

919.0    

 

(18.7)   

 

900.3    

  Depreciation, Decommissioning

           

    and Amortization

 

241.7    

 

(7.7)   

 

234.0    

  Property and Revenue Taxes

 

77.0    

 

(3.8)   

 

73.2    

Operating Income

 

$409.1    

 

$3.4    

 

$405.7    

During September 2007, we completed the sale of Point Beach. In connection with the sale, a power purchase agreement with an affiliate of FPL became effective to purchase all of the existing energy and capacity produced by Point Beach. As a result of the sale and the power purchase agreement, we expect future income statements to look different than historical income statements. Prospectively, we expect to see significantly higher purchased power expense because we will be purchasing energy from the new owner of Point Beach. We also expect to see a reduction of other operation and maintenance costs, as well as lower depreciation, decommissioning and amortization costs because we no longer own Point Beach. Finally, under the power purchase agreement, we will pay higher amounts per MWh for purchased power in the summer months and lower amounts in the non-summer months.

 

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the first nine months of 2007 with the first nine months of 2006.


29


   

Nine Months Ended September 30

   

Electric Revenues

 

MWh Sales

   

2007

 

B (W)

 

2006

 

2007

 

B (W)

 

2006

   

(Millions of Dollars)

 

(Thousands)

Customer Class

                       

  Residential

 

$701.4   

 

$46.9   

 

$654.5   

 

6,474.0  

 

226.6  

 

6,247.4  

  Small Commercial/Industrial

652.3   

42.8   

609.5   

7,140.8  

200.6  

6,940.2  

  Large Commercial/Industrial

519.3   

32.9   

486.4   

8,510.0  

12.4  

8,497.6  

  Other-Retail

 

14.4   

 

0.5   

 

13.9   

 

122.8  

 

(0.7) 

 

123.5  

    Total Retail Sales

 

1,887.4   

 

123.1   

 

1,764.3   

 

22,247.6  

 

438.9  

 

21,808.7  

  Wholesale-Other

 

72.6   

 

14.6   

 

58.0   

 

1,590.4  

 

33.0  

 

1,557.4  

  Resale-Utilities

 

45.5   

 

(3.9)  

 

49.4   

 

705.6  

 

(283.3) 

 

988.9  

  Other Operating Revenues

32.0   

2.7   

29.3   

-     

-      

-     

Total

$2,037.5   

$136.5   

$1,901.0   

24,543.6  

188.6  

24,355.0  

Weather -- Degree Days (a)

                       

  Heating (4,309 Normal)

             

4,259   

 

425  

 

3,834  

  Cooling (714 Normal)

             

755   

 

35   

 

720  

(a)

As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

During the first nine months of 2007, electric utility operating revenues increased by $136.5 million, or approximately 7.2%, when compared to the first nine months of 2006. The most significant increase in revenues relates to the recognition of revenues attributable to fuel and purchased power. Our policy for electric fuel revenues is to not recognize revenue for any currently billable amounts if it is probable that we will refund those amounts to customers. In 2006, we experienced lower than expected fuel and purchased power costs, and we established $48.7 million of reserves to reflect amounts that we expected to refund to customers. No such reserves have been established in 2007 as we are experiencing higher fuel and purchased power costs. In addition, we estimate that $33.5 million of the increase in operating revenues relates to pricing increases. This increase primarily reflects rate increases received in late January 2006 that were in effect for the entire nine month period ended September 30, 2007 and the wholesale rate increase effective in May 2007. We also estimate that $13.5 million of the increase was due to more favorable weather and $22.9 million relates to sales growth in residential and commercial sales. Approximately $9.0 million of the increase relates to the settlement in the second quarter of 2007 of a billing dispute with our largest customers, two iron ore mines.

Our retail electric sales volume increased by approximately 2.0%. The increase in retail sales was driven by growth in residential and commercial sales and favorable winter weather in 2007 as compared to the same period in 2006. As measured by heating degree days, the first nine months of 2007 were 11.1% colder than the same period in 2006, increasing heating load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. The increase in retail sales was offset by a 28.6% decline in sales volumes to other utilities due to lower plant availability during the nine months ended September 30, 2007.

 

Fuel and Purchased Power

Our fuel and purchased power costs increased by $132.3 million, or 22.5%, when compared to the first nine months of 2006. Our total electric sales volume increased by approximately 0.8% in the first nine months of 2007. However, our average fuel and purchased power cost per MWh also increased by $5.01 or approximately 22.3%. In the first nine months of 2007, we had a 10.5% reduction in MWh output at our nuclear units due primarily to a planned refueling outage at Point Beach during the second quarter of 2007. In 2006, the scheduled refueling outage at Point Beach occurred in the fourth quarter. Additionally, generation from our coal units was 7.6% lower in the first nine months of 2007 due


30


primarily to coal unit outages in the first quarter of 2007 as compared to 2006. As a result of the reduced coal and nuclear output, approximately 23.4% of our MWh sales in the first nine months of 2007 were supplied by higher cost natural gas-fired generation and purchased power as compared to 15.8% in the first nine months of 2006.

For further information, see Factors Affecting Results, Liquidity and Capital Resources - Utility Rates and Regulatory Matters below.

 

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first nine months of 2007 with the first nine months of 2006. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas margins increased by approximately $23.4 million, or 8.4%, primarily because of the new rates that went into effect at the end of January 2006.

Nine Months Ended September 30

2007

B (W)

2006

(Millions of Dollars)

Gas Operating Revenues

$1,011.8   

$38.7   

$973.1   

Cost of Gas Sold

710.4   

(15.3)  

695.1   

Gross Margin

$301.4   

$23.4   

$278.0   

 

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2007 with the first nine months of 2006.

Nine Months Ended September 30

Gross Margin

Therm Deliveries

2007

B (W)

2006

2007

B (W)

2006

(Millions of Dollars)

(Millions)

Customer Class

  Residential

$190.6   

$15.5   

$175.1   

533.7   

54.8   

478.9   

  Commercial/Industrial

65.0   

7.1   

57.9   

316.7   

26.4   

290.3   

  Interruptible

1.5   

0.1   

1.4   

16.8   

2.2   

14.6   

    Total Retail Gas Sales

257.1   

22.7   

234.4   

867.2   

83.4   

783.8   

  Transported Gas

38.0   

0.3   

37.7   

683.5   

53.0   

630.5   

  Other

6.3   

0.4   

5.9   

-       

-       

-       

Total

$301.4   

$23.4   

$278.0   

1,550.7   

136.4   

1,414.3   

Weather -- Degree Days (a)

  Heating (4,309 Normal)

4,259   

425  

3,834   

(a)

As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

Our gas margins increased by $23.4 million, or 8.4%, when compared to the first nine months of 2006. We estimate that approximately $17.1 million of this increase related to increased sales as a result of more normal winter weather. The first nine months of 2007 were approximately 11.1% colder than the same period in 2006. As a result, our retail therm deliveries increased approximately 10.6% as compared to the first nine months of 2006. In addition, we estimate that our gas margins improved by


31


approximately $6.6 million due to a rate order that went into effect in the latter part of January 2006 and was effective for the entire nine month period ended September 30, 2007.

 

Other Operation and Maintenance Expenses

Our other operation and maintenance expenses increased by $18.7 million, or approximately 2.1%, when compared to the first nine months of 2006. In January 2006, we received a rate order to cover increased expenses related to transmission costs, bad debt costs and PTF costs. We estimate that for the first nine months of 2007, other operation and maintenance expenses (and revenues) were approximately $12.7 million higher than the same period last year as a result of the January 2006 rate order. In the first nine months of 2007, we had a scheduled nuclear refueling outage. We did not have a similar outage in the first nine months of 2006. This resulted in an increase of approximately $17.5 million in nuclear operation and maintenance expenses between the comparative periods. This increase was offset, in part, by a $16.2 million reduction in benefit related costs and other factors.

 

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

Corporate and other affiliates had an operating loss of $0.7 million for the nine months ended September 30, 2007 compared with an operating loss of $9.3 million for the same period in 2006. The favorable change is primarily related to our Wispark operations, which had operating income during the first nine months of 2007 as compared to operating losses for the same period in 2006.

 

CONSOLIDATED OTHER INCOME, NET

Other income, net increased by approximately $3.0 million, or 6.7%, when compared to the nine months ended September 30, 2006. The increase reflects approximately $10.4 million of pre-tax gains on property sales in 2007 compared with a pre-tax gain on the sale of our investment in Guardian Pipeline LLC of $2.8 million during the same period in 2006. The largest gains in 2007 relate to land sold in Northern Wisconsin and the Upper Peninsula of Michigan. We had additional capitalized carrying costs and gross receipts tax of approximately $5.4 million during the nine months ended September 30, 2007. These increases were offset, in part, by a decrease of $8.1 million in AFUDC. This reduction primarily reflects the new scrubber we put in service at our Pleasant Prairie Power Plant during the fourth quarter of 2006. This scrubber was installed as part of our EPA consent decree spending. For further information on the consent decree with the EPA, see Note 12 -- Commitments and Contingencies in this report, as well as Note S -- Commitments and Contingencies in our 2006 Annual Report on Form 10-K. Furthermore, our interest in the earnings of unconsolidated affiliates decreased approximately $3.2 million when compared to the nine months ended September 30, 2006.

 

CONSOLIDATED INTEREST EXPENSE

Nine Months Ended September 30

Interest Expense

2007

2006

(Millions of Dollars)

Gross Interest Costs

$179.2   

$156.4   

Less: Capitalized Interest

52.0   

27.1   

Interest Expense

$127.2   

$129.3   



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Our gross interest costs increased by $22.8 million, or 14.6%, in the nine months ended September 30, 2007 when compared with the same period in 2006. This increase reflects higher debt levels as a result of our PTF construction program. However, in connection with the PTF construction program we capitalize interest during construction. Our capitalized interest increased by $24.9 million due to higher levels of construction in progress at our PTF plants. As a result, our net interest expense declined by $2.1 million, or 1.6%, as compared to the first nine months of 2006.



CONSOLIDATED INCOME TAXES

For the first nine months of 2007, our effective tax rate applicable to continuing operations was 38.8% compared to 37.2% for the first nine months of 2006. We expect our 2007 annual effective tax rate to be between 38.0% and 39.0%. For additional information, see Note H -- Income Taxes in our 2006 Annual Report on Form 10-K.

 

DISCONTINUED OPERATIONS

Income from discontinued operations, net of tax decreased by $5.1 million in the nine months ended September 30, 2007 as compared to the same period in 2006. In the nine months ended September 30, 2006, we had income of approximately $4.5 million related to the favorable resolution of tax liabilities.

 

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following summarizes our cash flows during the first nine months of 2007 and 2006:

   

Nine Months Ended September 30

Wisconsin Energy Corporation

 

2007

 

2006

   

(Millions of Dollars)

Cash Provided by (Used in)

       

   Operating Activities

 

$632.7    

 

$708.3    

   Investing Activities

 

($386.4)   

 

($650.3)   

   Financing Activities

$216.7    

($110.0)   

Operating Activities

Cash provided by operating activities was $632.7 million during the nine months ended September 30, 2007, or $75.6 million lower than the comparable period in 2006. This decline was due primarily to fuel recoveries, higher tax payments and changes in working capital requirements. Tax payments increased as a result of higher taxable income in 2007 and due to the prepaid balance of income taxes as of December 31, 2005, which reduced tax payments in 2006. In the nine months ended September 30, 2007, we had unfavorable recoveries of fuel and purchased power costs of $39.5 million. In the same period in 2006, we had favorable recoveries of fuel and purchased power costs of $56.7 million. In addition, we experienced an increase in working capital requirements.


33


Investing Activities

Cash used in investing activities was $386.4 million during the nine months ended September 30, 2007, or $263.9 million lower than the comparable period in 2006. In September 2007, we sold Point Beach to an affiliate of FPL and received approximately $924 million. In connection with the sale, we also transferred $390 million of decommissioning funds to the buyer and retained approximately $552 million of decommissioning funds. After subtracting the book value of the plant and transaction costs, the net gain from the sale, as well as the decommissioning funds that we retained, are expected to be used for the benefit of our customers, as determined by our regulators. To that end, we have placed approximately $969 million of proceeds in a separate interest bearing bank account for the benefit of our customers. We expect to use a portion of these proceeds to pay tax obligations related to the liquidation of the qualified decommissioning trust due in the fourth quarter of 2007, and to withdraw the remaining funds to offset the cash impact of bill credits that we expect to apply to our customers' bills over the next two years. We anticipate that substantially all of the $969 million of restricted cash, after the payment of related taxes, will be withdrawn to offset customer bill credits before December 31, 2009. The sales proceeds were offset by increased capital expenditures of $178.2 million for the nine months ended September 30, 2007, primarily due to the increased levels of construction at the PTF plants.

Financing Activities

Cash provided by financing activities was $216.7 million during the nine months ended September 30, 2007, or $326.7 million greater than the comparable period in 2006. During 2007, we received $523.4 million of cash proceeds from the issuance of debt, including the $500 million principal amount of Junior Notes sold in May 2007. We used the net proceeds of the Junior Notes to pay down short-term debt incurred both to fund PTF and for other working capital purposes. In addition, we paid off all of Wisconsin Electric Fuel Trust's outstanding commercial paper, aggregating $76.2 million.

In the first nine months of 2007, we received proceeds of $30.6 million related to the exercise of stock options, compared with $12.5 million in the first nine months of 2006. Instead of issuing new shares for these stock options, we instructed our plan agent to purchase common stock in the open market at a cost of $55.7 million, compared with $21.8 million in the first nine months of 2006. This cost is included in Purchase of common stock on our Consolidated Condensed Statements of Cash Flows.

 

CAPITAL RESOURCES AND REQUIREMENTS

Capital Resources

We anticipate meeting our capital requirements during the remaining three months of 2007 primarily through internally generated funds, short-term borrowings and the application of the proceeds from the sale of assets, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors. Beyond 2007, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by short-term borrowings and the issuance of debt securities.

We have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, our access to capital markets and internally generated cash.



34


In May 2007, Wisconsin Energy filed a shelf registration statement with the SEC for an unspecified amount of debt securities, which became effective upon filing. We issued the Junior Notes pursuant to this registration statement in May 2007.

In August 2007, Wisconsin Electric filed a shelf registration statement with the SEC to issue up to $800 million in debt securities. The registration statement has been declared effective by the SEC and, subject to market conditions, is available for use.

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit agreements provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.

As of September 30, 2007, we had approximately $1.7 billion of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $831.3 million of total consolidated short-term debt outstanding.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities at September 30, 2007:


Company

 


Total Facility

 

Letters of
Credit

 


Credit Available

 

Facility
Expiration

 

Facility
Term

   

(Millions of Dollars)

       
                     

  Wisconsin Energy

 

$900.0     

 

$1.5    

 

$898.5     

 

April 2011   

 

5 year     

  Wisconsin Electric

 

$500.0     

 

$4.1    

 

$495.9     

 

March 2011   

 

5 year     

  Wisconsin Gas

 

$300.0     

 

$  -      

 

$300.0     

 

March 2011   

 

5 year     

 

The following table shows our actual capitalization structure as of September 30, 2007, as well as, an adjusted capitalization structure that is consistent with the manner in which the rating agencies currently view the Junior Notes:

Capitalization Structure

Actual

Adjusted

(Millions of Dollars)

Common Equity

$3,034.6 

39.6% 

$3,284.6 

42.8% 

Preferred Stock of Subsidiary

30.4 

0.4% 

30.4 

0.4% 

Long-Term Debt (including

  current maturities)

3,775.7 

49.2% 

3,525.7 

46.0% 

Short-Term Debt

831.3 

10.8% 

831.3 

10.8% 

     Total Capitalization

$7,672.0 

100.0% 

$7,672.0 

100.0% 

Total Debt

$4,607.0 

$4,357.0 

Ratio of Debt to Total Capitalization

60.0% 

56.8% 

Included in Long-Term Debt as of September 30, 2007, is the $500 million aggregate principal amount of the Junior Notes as these debt securities are reflected as long-term debt on our Consolidated Condensed Balance Sheets. The adjusted presentation attributes $250 million of the Junior Notes to Common Equity and $250 million to Long-Term Debt. We believe this presentation is consistent with the way the majority of rating agencies treat the Junior Notes, where they attribute 50% equity credit to the Junior Notes.


35


The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages Wisconsin Energy's capitalization structure, including its total debt to total capitalization ratio, using the GAAP calculation and the rating agency treatment of the Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

We received $486 million of unrestricted cash proceeds from the sale of Point Beach. The closing of the sale of Point Beach was expected to occur during the third quarter of 2007, subject to the receipt of regulatory approvals. However, as it turned out, the actual closing did not take place until the afternoon of the last business day of the third quarter of 2007. If the closing had occurred earlier in the third quarter of 2007, we intended to use all of the unrestricted cash proceeds to retire short-term debt during the third quarter. Due to the actual timing of the closing, we had to extend the maturity of some of our short-term debt beyond the end of the third quarter, and were unable to use such proceeds during the third quarter as intended. On October 1, 2007, we used $281.4 million of the unrestricted cash proceeds to repay short-term debt. We are continuing to use the remaining unrestricted cash proceeds to repay short-term debt as it matures and to fund current expenditures instead of borrowing additional funds. We expect to use all of the unrestricted cash proceeds in this manner during the fourth quarter. Had we been able to use all $486 million of unrestricted cash proceeds to repay short-term debt during the third quarter, our pro-forma debt to total capitalization ratio, adjusted to reflect the rating agency equity treatment, would have been 53.9% as of September 30, 2007. The pro forma capitalization structure would have reflected $3,284.6 million of common equity (45.7%), $30.4 million of preferred stock of subsidiary (0.4%), $3,525.7 million of long-term debt (49.1%) and $345.3 million of short-term debt (4.8%), with a total capitalization of $7,186.0 million. We expect that we will have to borrow additional amounts during the remainder of 2007 and that our adjusted debt to total capitalization ratio, adjusted to reflect the rating agency equity treatment, will be above 53.9% at the end of 2007.

Absent the circumstances described above, Wisconsin Energy would not maintain such a large cash balance at the end of a quarter. Therefore, we believe it is important for our investors to understand how our adjusted capitalization structure would have looked if we had received the proceeds from the sale of Point Beach in time to use the unrestricted cash to repay short-term debt during the third quarter.

For additional information related to the proceeds received from the sale of Point Beach, see Note 4 -- Sale of Point Beach in the notes to consolidated Condensed Financial Statements in this report.

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our debt securities and the debt securities and preferred stock of our subsidiaries by S&P, Moody's and Fitch as of September 30, 2007.



36



S&P

Moody's

Fitch

Wisconsin Energy

   Commercial Paper

A-2

P-2

F2

   Unsecured Senior Debt

BBB+

A3

A-

   Unsecured Junior Notes

BBB-

Baa1

BBB+

Wisconsin Electric

   Commercial Paper

A-2

P-1

F1

   Unsecured Debt

A-

A1

A+

   Preferred Stock

BBB

A3

A

Wisconsin Gas

   Commercial Paper

A-2

P-1

F1

   Unsecured Senior Debt

A-

A1

A+

Wisconsin Energy Capital Corporation

   Unsecured Debt

BBB+

A3

A-

In July 2007, S&P affirmed the corporate credit ratings of Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation and revised the ratings outlooks assigned each company from negative to stable.

For additional information on these security ratings and other ratings outlooks assigned to Wisconsin Energy and its subsidiaries, see Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Requirements -- Capital Resources in our 2006 Annual Report on Form 10-K.

We believe these security ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Capital Requirements

Capital requirements during the remainder of 2007 are expected to be principally for capital expenditures and long-term debt maturities. Wisconsin Electric expects to retire at the scheduled maturity date, $250 million of 3.50% debentures due December 1, 2007. Our 2007 annual consolidated capital expenditure budget, excluding the purchase of nuclear fuel, is approximately $1,371.0 million.

In anticipation of the sale of Point Beach, in September 2007, Wisconsin Electric terminated its nuclear fuel lease and paid off all of Wisconsin Electric Fuel Trust's outstanding commercial paper, aggregating $76.2 million.

Off-Balance Sheet Arrangements:   We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 10 -- Guarantees in the Notes to Consolidated Condensed Financial Statements in this report.



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We have identified three tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of any of these three variable interest entities as defined by FIN 46. As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and for the other two contracts as operating leases. For additional information, see Note G -- Variable Interest Entities in our 2006 Annual Report on Form 10-K. We have included our contractual obligations under all three of these contracts in our evaluation of Contractual Obligations/Commercial Commitments discussed below.

Contractual Obligations/Commercial Commitments:   Our total contractual obligations and other commercial commitments increased to approximately $22.0 billion as of September 30, 2007 compared with $10.2 billion as of December 31, 2006. This increase was due primarily to the implementation of the Point Beach Nuclear Plant Power Purchase Agreement, which is a 26 year agreement, the issuance in May 2007 of the Junior Notes and agreements entered into in connection with our wind generation project. This increase was offset, in part, by assigning obligations related to Point Beach to an affiliate of FPL as part of the sale of Point Beach. In addition, we made periodic payments related to these types of obligations in the ordinary course of business during the nine months ended September 30, 2007. For purposes of determining our contractual obligations and commercial commitments only, we assumed the Junior Notes would be retired in 2017 with the proceeds from the issuance of qualifying securities pursuant to the terms of the RCC.

 

FACTORS AFFECTING RESULTS, LIQUDITY AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity and capital resources. The following discussion should be read together with the information under the heading "Factors Affecting Results, Liquidity and Capital Resources" in Item 7 of our 2006 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, our PTF strategy, utility rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring and competition and other matters.

 

POWER THE FUTURE

Under our PTF strategy, we expect to meet a significant portion of our future generation needs through the construction of the PWGS and the Oak Creek expansion by We Power. We Power will lease the new units to Wisconsin Electric under long-term leases, and we expect Wisconsin Electric to recover the lease payments in its electric rates. See Note E -- Accounting and Reporting for Power the Future Generating Units in the Notes to Consolidated Financial Statements and Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2006 Annual Report on Form 10-K and Note 3 -- Accounting and Reporting for Power the Future Generating Units in the Notes to Consolidated Condensed Financial Statements in this report for additional information on PTF.

Port Washington:   Construction of PWGS 2 is well underway. Site preparation, including removal of the old coal units at the site, was completed in early 2006, and all of the major components have been procured. The unit is expected to begin commercial operation during the second quarter of 2008.

Oak Creek Expansion:   The Oak Creek expansion includes a new coal handling system that will serve both the existing units at Oak Creek and OC 1 and OC 2. The new coal handling system is expected to be placed into service during the fourth quarter of 2007 at a cost of approximately $170 million. We estimate the annual revenues associated with the coal handling system will be approximately $23 million.



38


The CPCN granted for the construction of the Oak Creek expansion was the subject of a number of legal challenges by third parties; these legal challenges were resolved in June 2005. We have received all permits necessary to commence construction, which began in June 2005. Certain of these permits continue to be contested but remain in effect unless and until overturned by a reviewing court or ALJ.

A contested case hearing for the WPDES permit was held in March 2006. The ALJ upheld the issuance of the permit in a decision issued in July 2006. In August 2006, the opponents filed in Dane County Circuit Court for judicial review of the ALJ's decision upholding the issuance of the permit. In March 2007, the Dane County Circuit Court affirmed in part the decision by the ALJ to uphold the WDNR's issuance of the permit. The Court also remanded certain aspects of the ALJ's decision for further consideration based on the January 2007 decision by the Federal Court of Appeals for the Second Circuit concerning the federal rule on cooling water intake systems for existing facilities (the Phase II rule) (Riverkeeper, Inc. v. EPA, 475 F.3d 83 (2d Cir. 2007)). The Second Circuit found certain portions of the Phase II rule impermissible and remanded several parts of the Phase II rule to the EPA for further consideration or potential additional rulemaking. Consistent with its announcement in March, in July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems.

In light of these actions, we have requested that the WDNR modify the WPDES permit. We have submitted additional information to the WDNR as part of that process. In early May 2007, we requested that the ALJ stay the proceedings on remand pending WDNR's review of our request to modify the WPDES permit. The ALJ granted our motion for a stay; however, based on a request from the opponents, the Dane County Circuit Court subsequently issued a decision "clarifying" its March order of remand. Thereafter, in August 2007, the ALJ issued a new scheduling order. According to that schedule, we anticipate a decision on the issue before the ALJ by the end of November 2007. After the ALJ's decision, WDNR will proceed to complete the permit modification process, which we expect could take until early 2008. When a permit is modified through the modification procedure under state law, as under federal regulations, the existing permit continues in full force and effect during the modification process.

 

UTILITY RATES AND REGULATORY MATTERS

2008 Rate Case

In May 2007, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. Wisconsin Electric has asked the PSCW to approve a comprehensive plan which would result in net price increases of 7.5% in 2008 and 7.5% in 2009 for its electric customers in Wisconsin, a 1.8% price increase in 2008 for its gas customers and approximately 16.0% price increases in 2008 for all steam customers in Milwaukee. Wisconsin Gas has filed for a 4.1% price increase in 2008 for its gas customers.

Electric pricing increases are largely needed to allow us to continue progress on previously approved initiatives, including: costs associated with generation capacities, primarily the new PTF plants approved by the PSCW in 2002 and 2003; recovery of costs associated with transmission; compliance with environmental regulations; continuation of investment in renewable and efficiency programs, including the new wind facilities approved by the PSCW in February 2007; and scheduled recovery of regulatory assets.

The proposed net price increase for electric customers in Wisconsin reflects credits expected to be applied from the sale of Point Beach. In our May 2007 filing, we anticipated that there would be approximately $653 million of credits available for Wisconsin customers. Now, we anticipate that there


39


are approximately $696 million of proceeds from the sale of Point Beach to offset the required price increases in Wisconsin. Our proposed plan, if approved by the PSCW, would apply $107 million to recover existing regulatory assets in 2008. Our plan would provide monthly bill credits of approximately $372 million in 2008 and $188 million, including interest, in 2009, and any remaining proceeds in our next scheduled rate filing. The proposed credits are expected to have a significant impact on net price increases for electric customers. For example, a $50 million increase or decrease in the pricing credits provided in 2008, while leaving the other components of our proposal unchanged, would result in a corresponding decrease or increase of approximately 2.5% in the net price change to electric customers in 2008. The new prices, which will be subject to a full review by the PSCW, are expected to be implemented in January 2008.

2006 Rate Order

Electric Rates:   In January 2006, Wisconsin Electric received an order from the PSCW that allowed it to increase annual electric revenues by approximately $222.0 million, or 10.6%, to recover increased costs associated with investments in our PTF units, transmission services and fuel and purchased power, as well as costs associated with additional sources of renewable energy. The rate increase was based on an authorized return on equity of 11.2%. The order also required Wisconsin Electric to refund to customers, with interest, any fuel revenues that it received in excess of fuel and purchased power costs that it incurred, as defined by the Wisconsin fuel rules. The original order stipulated that any refund would also include interest at short-term rates. This refund provision expired December 31, 2006.

During 2006, we experienced lower than expected fuel and purchased power costs. In September 2006, we requested and received approval from the PSCW to refund favorable fuel recoveries including accrued interest at short-term rates. In addition, in September 2006 the PSCW determined that if the total recoveries for 2006 exceeded $36 million, interest on the amount in excess of $36 million would be paid at the rate of 11.2%, our authorized return on equity, rather than at short-term rates as originally set forth in the order. During October 2006, we refunded $28.7 million, including interest, to Wisconsin retail customers as a credit on their bill and an additional $10.3 million, including interest, in the first quarter of 2007.

In 2007, Wisconsin Electric returned to the traditional fuel cost adjustment clause in the Wisconsin retail jurisdiction whereby fuel revenues may be adjusted prospectively if fuel and purchased power costs fall outside a pre-established annual band of plus or minus 2%.

Gas Rates:   Our gas operations went through a traditional rate proceeding whereby the revenues were set to recover projected costs and to provide a return on rate base. The January 2006 order provided for increases in gas revenues totaling $60.1 million annually ($21.4 million, or 2.9%, for Wisconsin Electric gas operations and $38.7 million, or 3.7%, for Wisconsin Gas gas operations). The rate increases were based on an authorized return on equity of 11.2% for the gas operations of both Wisconsin Electric and Wisconsin Gas.

Steam Rates:   The steam rate proceeding was a traditional rate proceeding. The January 2006 order provided for an increase in steam rates of $7.8 million, or 31.5%, to be phased in over a two year period beginning in 2006. The rate increase was based on an authorized return on equity of 11.2%.

Limited Rate Adjustment Requests

2005 Fuel Recovery Filing:   In February 2005, Wisconsin Electric filed an application with the PSCW for an increase in electric rates in the amount of $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in our reliance upon natural gas as a

40


fuel source. We received approval for the increase in fuel recoveries on an interim basis in March 2005. In November 2005, we received the final rate order, which authorized an additional $7.7 million in rate increases, for a total increase of $122.6 million (6.2%). In December 2005, two parties filed suit against the PSCW in Dane County Circuit Court challenging the PSCW's decision to allow fuel cost recovery, while allowing us to keep the savings that resulted from the WICOR, Inc. acquisition. As a condition of the PSCW approval of the WICOR, Inc. acquisition, Wisconsin Electric and Wisconsin Gas were restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions, but we were allowed to keep the savings generated from the merger. In July 2006, the Dane County Circuit Court affirmed the PSCW's decision. In August 2006, the opponents appealed this decision to the Wisconsin Court of Appeals. In July 2007, the Court of Appeals affirmed the Dane County Circuit Court decision upholding the PSCW's order. The time period for further appeal has expired and no appeal was filed.

Other Regulatory Matters

Coal Generation Forced Outage - 2007:   In March 2007, we requested and received approval from the PSCW to defer as a regulatory asset approximately $13.2 million related to replacement power costs due to a forced outage of Unit 1 at the Pleasant Prairie Power Plant. The outage extended from February 2007 through March 2007.

Wholesale Electric Rates:   In August 2006, Wisconsin Electric filed a wholesale rate case with FERC. The filing requested an annual increase in rates of approximately $16.7 million applicable to four existing wholesale electric customers. This includes a mechanism for fuel and other cost adjustments. In November 2006, FERC accepted the rate filing subject to refund with interest. Three of the existing customers' rates were effective in January 2007. The remaining largest wholesale customer's rates were effective in May 2007. FERC approved a settlement of the rate filing in September 2007.

Fuel Rules:   In June 2006, the PSCW opened a docket (01-AC-224) in which it was looking into revising the current fuel rules (Chapter PSC 116). In February 2007, five Wisconsin utilities regulated by the fuel rules, including Wisconsin Electric, filed a joint proposal to modify the existing rules in this docket. The proposal recommends modifying the rules to allow for escrow accounting for fuel costs outside a plus or minus 1% annual band of fuel costs allowed in rates. It further recommends that the escrow balance be trued-up annually following the end of each calendar year. We are unable to predict if or when the PSCW will make any changes to the existing fuel rules.

See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding our utility rates and other regulatory matters.

 

WIND GENERATION

In June 2005, we purchased the development rights to two wind farm projects (Blue Sky Green Field) from Navitas Energy Inc. In March 2006, we filed for approval of a CPCN with the PSCW. Hearings were held at the end of November 2006. In February 2007, the PSCW issued a written notice approving the CPCN. During March 2007, we entered into a final agreement with Vestas Wind Systems for the purchase of wind turbines with a combined generating capacity of 145 MW. In May 2007, we entered into an agreement with Alliant Energy EPC, LLC to construct the wind farm. In addition to the CPCN approval, we secured other required permits, including all requested Federal Aviation Administration permits, and began construction in June 2007. Equipment is expected to begin arriving at the site during the fourth quarter of 2007. We have also entered into service and warranty agreements with Vestas Wind Systems that will cover the first two years of operation. We estimate that the capital cost of the project,


41


excluding AFUDC, will be approximately $300 million. We currently expect the turbines to be placed into service no later than the second quarter of 2008.

In addition, in October 2007, we provided notice to FPL Energy, a subsidiary of FPL, that we were exercising the option we received in connection with the sale of Point Beach to purchase all rights to a new wind site in Central Wisconsin. Once the purchase is complete, we expect to install approximately 100 MW of generating capacity. We expect the turbines to be placed into service during late 2011 or 2012, subject to regulatory approvals and turbine availability.

 

NUCLEAR OPERATIONS

In September 2007, Wisconsin Electric sold Point Beach to an affiliate of FPL for approximately $924 million. Upon closing of the sale, the power purchase agreement became effective for the existing energy and capacity produced by Point Beach. See Note 4 -- Sale of Point Beach in the Notes to Consolidated Condensed Financial Statements in this report and Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding the sale of Point Beach.

 

ELECTRIC TRANSMISSION

MISO:    In connection with its status as a FERC approved Regional Transmission Organization, MISO implemented a bid-based energy market, the MISO Midwest Market, which commenced operations on April 1, 2005. In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of RSG charges. FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. In October 2006 and March 2007, we received additional rulings from FERC on these issues. FERC's rulings have been challenged by MISO and numerous other market participants. MISO commenced with the resettlement of the market in accordance with the orders in July 2007. Completion is anticipated in January 2008. Based on the current resettlement results, we are estimating net costs to increase by $9.0 million for the resettlement period. Several entities have filed official complaints with FERC on the assessment of these charges. We filed in support of these complaints. These challenges could partially reverse the current rulings.

As part of this energy market, MISO developed a market-based platform for valuing transmission congestion and losses premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through the use of FTRs. FTRs are allocated to market participants by MISO. A new allocation of FTRs was completed in April 2007 for the period June 1, 2007 through May 31, 2008. We were granted substantially all of the FTRs that we were permitted to request during the allocation process.

MISO is in the process of developing a market for two ancillary services, regulation reserves and contingency reserves. In February 2007, MISO filed tariff revisions to include ancillary services. In June 2007, FERC rejected this tariff filing. In September 2007, MISO filed a revised tariff, and it is currently under FERC review. The MISO ancillary services market is proposed to begin in 2008. We currently self-provide both regulation reserves and contingency reserves. In the MISO ancillary services market, we expect that we will buy/sell regulation and contingency reserves from/to the market. We expect the MISO ancillary services market to reduce overall ancillary services costs in the MISO footprint. We anticipate achieving a net reduction in fuel costs but are unable to determine the amount of savings we will realize at this time. The MISO ancillary services market is also expected to enable MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.


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See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Electric Transmission and Energy Markets in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding MISO.

 

ENVIRONMENTAL MATTERS

EPA - Consent Decree:   In April 2003, Wisconsin Electric and the EPA announced that a consent decree had been reached that resolved all issues related to a request for information that had been issued by the EPA. The U.S. District Court for the Eastern District of Wisconsin approved the amended consent decree and entered it in October 2007. For additional information, see Note 12 -- Commitments and Contingencies in the Notes to Consolidated Condensed Financial Statements in this report.

Clean Water Act:   Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the BTA for minimizing adverse environmental impact. This law dates back to 1972; however, prior to September 2004, there were no federal rules that defined precisely how states and EPA regions determined that an existing intake met BTA requirements. The Phase II rule established, for the first time, national performance standards and compliance alternatives for existing facilities that are designed to minimize the potential adverse environmental impacts to aquatic organisms associated with water withdrawals from cooling water intakes. Costs associated with implementation of the Phase II rule for Wisconsin Electric's Oak Creek Power Plant, We Power's Oak Creek expansion and PWGS were included in project costs.

In January 2007, the Federal Court of Appeals for the Second Circuit issued a decision concerning the Phase II rule for existing facilities (Riverkeeper, Inc. v. EPA, 475 F.3d 83 (2d Cir. 2007)). The Second Circuit found certain portions of the rule impermissible and remanded several parts of the Phase II rule to the EPA for further consideration or potential additional rulemaking. Consistent with its announcement in March, in July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems. We will work with the relevant state agencies as permits for our facilities come due for renewal to determine what, if any, actions need to be taken. Until the EPA completes its reconsideration and rulemaking, we cannot predict what impact these changes to the federal rules may have on our facilities. For additional information on this matter related to the Oak Creek expansion, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future -- Oak Creek Expansion in this report.

Greenhouse Gases:   We continue to take voluntary measures to reduce our emissions of greenhouse gases. We also continue to analyze the state and federal legislative proposals for greenhouse gas regulation, including mandatory restrictions on CO2; however, we are unable at this time to definitively determine the impact of such future regulations on our operations or rates. In addition, we continue to support flexible, market-based strategies to curb greenhouse gas emissions. Our emissions in future years will continue to be influenced by several actions completed, planned or underway as part of the PTF strategy.

National Ambient Air Quality Standards:   

8-hour Ozone Standard:   In June 2007, the EPA announced its proposal to further lower the 8-hour standard. The proposal is undergoing public comment. Until this proposal becomes a final rule, we are unable to predict the impact on the operation of our existing coal-fired generation facilities or our new PTF generating units.


PM2.5 Standard:   In December 2006, a more restrictive federal standard became effective, which may place some counties in Southeastern Wisconsin into non-attainment status. This standard is currently being litigated. Until such time as the states develop rules and submit State


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Implementation Plans to EPA to demonstrate how they intend to comply with the standard, we are unable to predict the impact of this more restrictive standard on the operation of our existing coal-fired generation facilities or our new PTF generating units.

Clean Air Interstate Rule:   The EPA issued the final CAIR regulation in March 2005 to facilitate the states in meeting the 8-hour ozone and PM2.5 standards by addressing the regional transport of SO2 and NOx. The states were required to develop and submit implementation plans by no later than March 2007. A final CAIR rule has been adopted in Wisconsin and Michigan. We believe that compliance with the NOx and SO2 emission reductions requirements under the agreement with the EPA will substantially mitigate costs to comply with the CAIR rule.

Clean Air Visibility Rule:   The EPA issued the CAVR in June 2005 to address regional haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines BART requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA's CAIR. Under CAVR, states are required to identify certain industrial facilities and power plants that affect visibility in the nation's 156 Class I protected areas. States are then required to determine the types of emission controls that those facilities must use to control their emissions. The pollutants from power plants that reduce visibility include particulate matter or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia. States must submit plans to implement CAVR to the EPA by December 2007. The reductions associated with the state plans are scheduled to begin to take effect in 2014, with full implementation before 2018. Wisconsin has issued draft rules which cover only one aspect of the regulations. Michigan has not yet issued a draft rule. Until the rules are final, we are unable to predict the impact on our system.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information concerning market risk exposures at Wisconsin Energy Corporation, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks, in Part II of our 2006 Annual Report on Form 10-K.

 

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures:   Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based upon such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.


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Internal Control Over Financial Reporting:   There has not been any change in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter to which this report relates that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.




PART II -- OTHER INFORMATION


ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2006 Annual Report on Form 10-K and Item 1. Legal Proceedings in Part II of our Quarterly Report on Form 10-Q for the periods ended March 31 and June 30, 2007.

In addition to those legal proceedings discussed in our reports to the SEC, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, we believe, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial condition.

 

UTILITY RATES AND REGULATORY MATTERS

See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Part I of this report for information concerning rate matters in the jurisdictions where Wisconsin Electric, Wisconsin Gas and Edison Sault do business.

Power the Future:   See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Part I of this report for information concerning our PTF strategy.

 

ITEM 1A. RISK FACTORS

See Item 1A. Risk Factors in our 2006 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.


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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three-month period ended September 30, 2007.







2007

 





Total Number of Shares
Purchased (a)

 





Average Price Paid per Share

 



Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs

 

Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

               

(Millions of Dollars)

                 

July 1-
July 31


-      


$    -     

 


-       

 


$   -      

                 

August 1-
August 31

 


464     


$43.31   

 

-       

 


$   -      

                 

September 1-
September 30

 


546      

 


$45.28   

 


-       

 


$   -      

Total

 

1,010      

 

$44.41   

 

-       

 

$   -      

(a)

This table does not include shares purchased by independent agents to satisfy obligations under our employee benefit plans and stock purchase and dividend reinvestment plan. All shares reported during the quarter were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.


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ITEM 6. EXHIBITS

         Exhibit Number

  

 

2  

Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

   

2.1  

Letter Agreement between Wisconsin Electric Power Company, FPL Energy Point Beach, LLC and FPL Group Capital, Inc., dated September 28, 2007, which amends the Asset Sale Agreement between the parties. (Exhibit 2.3 to Wisconsin Energy Corporation's 9/28/07 Form 8-K.)

   

10  

Material Contracts

   

10.1  

2007 Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan, as amended.

   

10.2  

Wisconsin Energy Corporation Performance Unit Plan, amended and restated effective as of October 11, 2007.

   

31  

Rule 13a-14(a) / 15d-14(a) Certifications

   

31.1  

Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.

   

31.2  

Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.

   

32  

Section 1350 Certifications

   

32.1  

Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

   

32.2  

Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

   


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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.

 

 

 
 

WISCONSIN ENERGY CORPORATION

 

(Registrant)

   
   

/s/STEPHEN P. DICKSON                          

Date: November 1, 2007

Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer


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