WEC Energy (WEC) 10-Q 6 May 10 2010 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information (USD $)
In Billions, except Share data	3 Months Ended Mar. 31, 2010	Jun. 30, 2009
Document and Entity Information [Abstract]
Entity Registrant Name	WISCONSIN ENERGY CORP
Entity Central Index Key	0000783325
Document Type	10-Q
Document Period End Date	2010-03-31
Amendment Flag	false
Document Fiscal Year Focus	2,010
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		4.8
Entity Common Stock, Shares Outstanding (actual number of shares)	116,900,740

Consolidated Condensed Income S

Consolidated Condensed Income Statements (Unaudited) (USD $)
In Millions, except Per Share data	3 Months Ended Mar. 31, 2010	3 Months Ended Mar. 31, 2009
Consolidated Condensed Income Statements [Abstract]
Operating Revenues	1255.9	1396.2
Operating Expenses
Fuel and purchased power	277.9	266.4
Cost of gas sold	355.8	502.7
Other operation and maintenance	339.7	334.4
Depreciation, decommissioning and amortization	75.2	85.8
Property and revenue taxes	27	28.1
Total Operating Expenses	1075.6	1217.4
Amortization of Gain	49.4	64.2
Operating Income	229.7	243
Equity in Earnings of Transmission Affiliate	15.2	14.3
Other Income, net	6.2	6.3
Interest Expense, net	49.4	40.8
Income from Continuing Operations Before Income Taxes	201.7	222.8
Income Taxes	71.9	81.3
Income from Continuing Operations	129.8	141.5
Loss from Discontinued Operations, Net of Tax	-0.1
Net Income	129.7	141.5
Earnings Per Share (Basic)
Continuing operations	1.11	1.21
Discontinued operations
Total Earnings Per Share (Basic)	1.11	1.21
Earnings Per Share (Diluted)
Continuing operations	1.1	1.2
Discontinued operations
Total Earnings Per Share (Diluted)	1.1	1.2
Weighted Average Common Shares Outstanding (Millions)
Basic	116.9	116.9
Diluted	118.4	118
Dividends Per Share of Common Stock	0.4	0.3375

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets (USD $)
In Millions	Mar. 31, 2010	Dec. 31, 2009
Property, Plant and Equipment
In service	$11,495	10286.6
Accumulated depreciation	-3524.5	-3472.2
Property Plant and Equipment net, In service	7970.5	6814.4
Construction work in progress	1197.6	2185.6
Leased facilities, net	69.1	70.5
Net Property, Plant and Equipment	9237.2	9070.5
Investments
Equity investment in transmission affiliate	321.2	314.6
Other	37.7	44.1
Total Investments	358.9	358.7
Current Assets
Cash and cash equivalents	12.8	20.9
Restricted cash	151	194.5
Accounts receivable	407.3	304.4
Accrued revenues	192.3	290.4
Materials, supplies and inventories	337	379.3
Regulatory assets	54.4	58.9
Prepayments and other	165.1	213.3
Total Current Assets	1319.9	1461.7
Deferred Charges and Other Assets
Regulatory assets	1,179	1192.5
Goodwill	441.9	441.9
Other	184.6	172.6
Total Deferred Charges and Other Assets	1805.5	1,807
Total Assets	12721.5	12697.9
Capitalization
Common equity	3641.8	3566.9
Preferred stock of subsidiary	30.4	30.4
Long-term debt	4396.1	3875.8
Total Capitalization	8068.3	7473.1
Current Liabilities
Long-term debt due currently	42.7	295.7
Short-term debt	478	825.1
Accounts payable	279	292.2
Regulatory liabilities	168.4	222.8
Other	287.2	246.1
Total Current Liabilities	1255.3	1881.9
Deferred Credits and Other Liabilities
Regulatory liabilities	896	886.7
Deferred income taxes - long-term	1038.9	1017.9
Deferred revenue, net	764.6	739.1
Pension and other benefit obligations	324.4	319.5
Other	374	379.7
Total Deferred Credits and Other Liabilities	3397.9	3342.9
Total Capitalization and Liabilities	12721.5	12697.9

Consolidated Condensed Statemen

Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $)
In Millions	3 Months Ended Mar. 31, 2010	3 Months Ended Mar. 31, 2009
Operating Activities
Net income	129.7	141.5
Reconciliation to cash
Depreciation, decommissioning and amortization	71.9	87.6
Amortization of gain	-49.4	-64.2
Equity in earnings of transmission affiliate	-15.2	-14.3
Distributions from transmission affiliate	12.5	11.4
Deferred income taxes and investment tax credits, net	5.1	-2.8
Deferred revenue	32.2	48.6
Contributions to benefit plans		-289.3
Change in -
Accounts receivable and accrued revenues	-33.7	-73.1
Inventories	42.3	93.4
Other current assets	12.2	8.9
Accounts payable	-36.1	-119.5
Accrued income taxes, net	48	82
Deferred costs, net	6.5	11.5
Other current liabilities	53.1	58.2
Other, net	24.6	40.4
Cash Provided by Operating Activities	303.7	20.3
Investing Activities
Capital expenditures	-194.6	-171.4
Investment in transmission affiliate	-3.9	-6.3
Proceeds from asset sales, net	0.2	0.1
Change in restricted cash	43.5	57.9
Other, net	-16.3	-23.3
Cash Used in Investing Activities	-171.1	(143)
Financing Activities
Exercise of stock options	19.9	3
Purchase of common stock	-31.8	-5.6
Dividends paid on common stock	-46.8	-39.5
Issuance of long-term debt	530	11.5
Retirement and repurchase of long-term debt	-261.7	-51.7
Change in short-term debt	-347.1	189
Other, net	-3.2	0.6
Cash (Used in) Provided by Financing Activities	-140.7	107.3
Change in Cash and Cash Equivalents	-8.1	-15.4
Cash and Cash Equivalents at Beginning of Period	20.9	32.5
Cash and Cash Equivalents at End of Period	12.8	17.1

General Information

General Information
	3 Months Ended Mar. 31, 2010
General Information [Abstract]
GENERAL INFORMATION	1 GENERAL INFORMATION Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item8, Financial Statements and Supplementary Data, in our 2009 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 months ended March31, 2010 are not necessarily indicative of the results which may be expected for the entire fiscal year 2010 because of seasonal and other factors.

New Accounting Pronouncements

New Accounting Pronouncements
	3 Months Ended Mar. 31, 2010
New Accounting Pronouncements [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	2 NEW ACCOUNTING PRONOUNCEMENTS Amendments to Variable Interest Entity Consolidation Guidance: In June2009, the FASB issued new accounting guidance related to variable interest entity consolidation. The purpose of this guidance is to improve financial reporting by enterprises with variable interest entities. The new guidance is effective for all new and existing variable interest entities for fiscal years beginning after November15, 2009. We adopted these provisions on January1, 2010. This adoption did not have any impact on our financial condition, results of operations or cash flows. See Note 12 Variable Interest Entities for required disclosures.

Accounting and Reporting for Po

Accounting and Reporting for Power the Future Generating Units
	3 Months Ended Mar. 31, 2010
Accounting and Reporting for Power the Future Generating Units [Abstract]
ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS	3 ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS Background: As part of our PTF strategy, our non-utility subsidiary, We Power, has built three new generating units (PWGS 1, PWGS 2 and OC 1) and is in the process of building another new generating unit, OC 2, which are, and will be, leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the PSCW. The leases are designed to recover the capital costs of the plant, including a return. PWGS 1 was placed in service in July2005, PWGS 2 was placed in service in May2008 and OC 1 was placed in service in February2010. The accompanying consolidated financial statements eliminate all intercompany transactions between We Power and Wisconsin Electric and reflect the cash inflows from Wisconsin Electric customers and the cash outflows to our vendors and suppliers. The Oak Creek expansion includes common projects that will benefit the existing units at this site as well as the new units. These projects include a coal handling facility and a water intake system, which were placed into service in November2007 and January2009, respectively. During Construction: Under the terms of each lease, we collect in current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for our 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 will be amortized to revenue over the term of each lease once the respective unit is placed into service. During the construction of our PTF units, we capitalize interest costs at an overall weighted-average pre-tax cost of interest which was approximately 5% for the three months ended March31, 2010 and for the twelve months ended December31, 2009. Capitalized interest is included in the total cost of the PTF units. Plant in Service: 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 on the investment. The authorized cash costs are established by the PSCW. The authorized cash costs exclude capitalized interest since 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 established a set return on equity component of 12.7% after tax. The interest component of the return is determined up to 180days prior to the date that the units are placed in service. We recognize revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease. We depreciate the units on a straight-line basis over their expected service life.

Common Equity

Common Equity
	3 Months Ended Mar. 31, 2010
Common Equity [Abstract]
COMMON EQUITY	4 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 2009 Annual Report on Form 10-K. We utilize the straight-line attribution method for recognizing share-based compensation expense. 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 by our independent agents are currently used to satisfy share-based awards. 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 for the three months ended March31: 2010 2009 (Millions of Dollars) Stock options $ 1.9 $ 2.5 Performance units 2.7 3.8 Restricted stock 0.3 0.2 Share-based compensation expense $ 4.9 $ 6.5 Related tax benefit $ 2.0 $ 2.6 Stock Option Activity: During the first three months of 2010, the Compensation Committee granted 274,750 options that had an estimated fair value of $6.72 per share. During the first three months of 2009, the Compensation Committee granted 1,216,625 options that had an estimated fair value of $8.01 per share. The following assumptions were used to value the options using a binomial option pricing model: 2010 2009 Risk-free interest rate 0.2% - 3.9 % 0.3% - 2.5 % Dividend yield 3.7% 3.0% Expected volatility 20.3% 25.9% Expected forfeiture rate 2.0% 2.0% Expected life (years) 5.9 6.2 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 during the three months ended March31, 2010: Weighted-Average Remaining Aggregate Number of Weighted-Average Contractual Life Intrinsic Value Stock Options Options Exercise Price (Years) (Millions) Outstanding as of January1, 2010 9,087,315 $ 38.49 Granted 274,750 $ 49.84 Exercised (630,079 ) $ 31.64 Forfeited (5,000 ) $ 45.70 Outstanding as of March31, 2010 8,726,986 $ 39.34 5.9 $ 88.0 Exercisable as of March31, 2010 5,947,441 $ 36.37 4.8 $ 77.6 The intrinsic value of options exercised was $11.5million and $2.5million for the three months ended Marc

Divestitures

Divestitures
	3 Months Ended Mar. 31, 2010
Divestitures [Abstract]
DIVESTITURES	5 DIVESTITURES Edgewater Generating Unit 5: During the fourth quarter of 2009, we reached a contingent agreement to sell our 25% interest in Edgewater Generating Unit 5 to WPL for our net book value, including working capital. In March2010, the agreement became effective and we are in the process of requesting regulatory approvals. The completion of the sale is subject to approval by applicable regulatory bodies, including the PSCW and MPSC. If approved, we expect the sale to close by the end of 2010 and to realize proceeds of between $40million and $45million depending on the working capital balances and our level of capital investment in the unit prior to the sale. Edison Sault: In October2009, we announced that we had reached an agreement to sell Edison Sault to Cloverland Electric Cooperative for approximately $61.5million, which represents a nominal gain. We will retain Edison Saults membership interest in ATC. The sale was contingent upon certain conditions, including regulatory approvals, the last of which was received subsequent to March31, 2010. For the quarter ended March31, 2010, Edison Saults operating revenues were $19.2 million. See Note 15 Subsequent Event Sale of Edison Sault for additional information on this sale.

Long Term Debt

Long Term Debt
	3 Months Ended Mar. 31, 2010
Long Term Debt [Abstract]
LONG TERM DEBT	6 LONG TERM DEBT In February2010, we issued a total of $530million in long-term debt ($255million aggregate principal amount of 5.209% SeriesA Senior Notes due February11, 2030 and $275million aggregate principal amount of 6.09% SeriesA Senior Notes due February11, 2040) and used the net proceeds to repay debt incurred to finance the construction of OC 1. This debt is secured by a collateral assignment of the lease between ERGSS and Wisconsin Electric.

Fair Value Measurements

Fair Value Measurements
	3 Months Ended Mar. 31, 2010
Fair Value Measurements [Abstract]
FAIR VALUE MEASUREMENTS	7 FAIR VALUE MEASUREMENTS Fair value measurements require enhanced disclosures about assets and liabilities that are measured and reported at fair value and establish a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. Accordingly, we also utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities measured and reported at fair value are classified and disclosed in one of the following categories: Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments. Level 2 Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as OTC forwards and options. Level 3 Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to fair value reporting and include in Level 3 all instruments whose fair value is based on significant unobservable inputs. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instruments level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument. The following tables summarize our financial assets and liabilities by level within the fair value hierarchy: Recurring Fair Value Measures As of March 31, 2010 Level 1 Level 2 Level 3 Total (Millions of Dollars) Assets: Restricted Cash $ 151.0 $ $ $ 151

Derivative Instruments

Derivative Instruments
	3 Months Ended Mar. 31, 2010
Derivative Instruments [Abstract]
DERIVATIVE INSTRUMENTS	8 DERIVATIVE INSTRUMENTS We utilize derivatives as part of our risk management program to manage the volatility and costs of purchased power, generation and natural gas purchases for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the PSCW. We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivatives fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. We do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of March31, 2010, we recognized $33.3million in regulatory assets and $12.6 million in regulatory liabilities related to derivatives in comparison to $19.1million in regulatory assets and $10.3million in regulatory liabilities as of December31, 2009. We record our current derivative assets on the balance sheet in Prepayments and other current assets and the current portion of the liabilities in Other current liabilities. The long-term portion of our derivative assets of $1.1million is recorded in Other deferred charges and other assets and the long-term portion of our derivative liabilities of $1.7million is recorded in Other deferred credits and other liabilities. Our Consolidated Condensed Balance Sheet as of March31, 2010 and December31, 2009 includes: March 31, 2010 December 31, 2009 Derivative Derivative Derivative Derivative Asset Liability Asset Liability (Millions of Dollars) Natural Gas $ 5.0 $ 22.7 $ 2.2 $ 9.3 Energy 1.0 Fuel Oil 0.8 0.6 FTRs 1.9 5.9 Coal 4.5 2.1 Total $ 13.2 $ 22.7 $ 10.8 $ 9.3 Our Consolidated Condensed Income Statements include gains (losses)on derivative instruments used in our risk management strategies under Fuel and purchased power for those commodities supporting our electric operations and under Cost of gas sold for the natural gas sold to our customers. Our estimated notional volumes and gain (losses)for the quarters ended March 31, 2010 and 2009 follow: March 31, 2010 March 31, 2009 Gains Gains Volume (Losses) Volume (Losses) (Millions of (Millions of Dollars) Dollars) Natural Gas 28.3 million Dth $ (11.7 ) 22.4 million

Benefits

Benefits
	3 Months Ended Mar. 31, 2010
Benefits [Abstract]
BENEFITS	9 BENEFITS The components of our net periodic pension and OPEB costs for the three months ended March31 were as follows: Pension Benefits OPEB Benefit Plan Cost Components 2010 2009 2010 2009 (Millions of Dollars) Net Periodic Benefit Cost Service cost $ 6.9 $ 5.3 $ 2.8 $ 2.3 Interest cost 17.4 18.2 5.4 5.3 Expected return on plan assets (19.7 ) (23.7 ) (3.6 ) (3.5 ) Amortization of: Transition obligation 0.1 0.1 Prior service cost (credit) 0.6 0.6 (3.0 ) (3.2 ) Actuarial loss 6.6 5.2 2.7 2.3 Net Periodic Benefit Cost $ 11.8 $ 5.6 $ 4.4 $ 3.3 In January2009, the committee that overseas the investment of the pension assets authorized the Trustee of pension plan to invest in the commercial paper of Wisconsin Energy. As of March31, 2010, the Pension Trust and OPBE plan assets held approximately $23.0million of commercial paper issued by Wisconsin Energy, which represents less than 10% of the total assets of the plan.

Guarantees

Guarantees
	3 Months Ended Mar. 31, 2010
Guarantees [Abstract]
GUARANTEES	10 GUARANTEES We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of March31, 2010, we had the following guarantees: Maximum Potential Future Payments Outstanding Liability Recorded (Millions of Dollars) $3.1 $ 0.3 $ A non-utility energy segment guarantee in support of Wisvest-Connecticut, which we sold in December2002 to PSEG, provides financial assurance for potential obligations relating to environmental remediation under the original purchase agreement for Wisvest-Connecticut with The United Illuminating Company. 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. We also provide guarantees to 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 is subject to the potential retrospective premiums that could be assessed under its insurance program. Postemployment Benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $16.3million as of March31, 2010 and $15.8million as of December31, 2009.

Segment Information

Segment Information
	3 Months Ended Mar. 31, 2010
Segment Information [Abstract]
SEGMENT INFORMATION	11 SEGMENT INFORMATION Summarized financial information concerning our reportable operating segments for the three month periods ended March31, 2010 and 2009 is shown in the following table: Corporate Reportable Operating Segments Other (a) Energy Reconciling Total Wisconsin Energy Corporation Utility Non-Utility Items Consolidated (Millions of Dollars) March31, 2010 Operating Revenues (b) $ 1,250.2 $ 65.5 $ (59.8 ) $ 1,255.9 Depreciation, Decommissioning and Amortization $ 63.3 $ 11.7 $ 0.2 $ 75.2 Operating Income (Loss) $ 179.4 $ 52.1 $ (1.8 ) $ 229.7 Equity in Earnings (Loss) of Unconsolidated Affiliates $ 15.2 $ $ (0.1 ) $ 15.1 Interest Expense, net $ 30.2 $ 7.4 $ 11.8 $ 49.4 Income Tax Expense (Benefit) $ 62.8 $ 18.4 $ (9.3 ) $ 71.9 Loss from Discontinued Operations, Net of Tax $ $ $ (0.1 ) $ (0.1 ) Net Income (Loss) $ 107.4 $ 26.3 $ (4.0 ) $ 129.7 Capital Expenditures $ 131.6 $ 62.6 $ 0.4 $ 194.6 Total Assets (c) $ 11,759.3 $ 2,909.5 $ (1,947.3 ) $ 12,721.5 March31, 2009 Operating Revenues (b) $ 1,395.6 $ 36.7 $ (36.1 ) $ 1,396.2 Depreciation, Decommissioning and Amortization $ 78.5 $ 7.2 $ 0.1 $ 85.8 Operating Income (Loss) $ 216.3 $ 27.9 $ (1.2 ) $ 243.0 Equity in Earnings (Loss) of Unconsolidated Affiliates $ 14.3 $ $ (0.1 ) $ 14.2 Interest Expense, net $ 30.1 $ 4.1 $ 6.6 $ 40.8 Income Tax Expense (Benefit) $ 73.4 $ 10.8 $ (2.9 ) $ 81.3 Income (Loss) from Discontinued Operations, Net of Tax $ 0.2 $ $ (0.2 ) $ Net Income (Loss) $ 133.4 $ 13.9 $ (5.8 ) $ 141.5 Capital Expenditures $ 130.2 $ 41.2 $ $ 171.4 Total Assets (c) $ 10,757.2 $ 2,536.7 $ (882.8 ) $ 12,411.1 (a) Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark, as well as interest on corporate debt. (b) An elimination for intersegment revenues of $60.0million and $36.2million is included in Operating Revenues for the three months ended March31, 2010 and 2009, respectively. This elimination is primarily between We Power and Wisconsin Electric. (c) An elimination of $1,837.7million and $900.7million is included in Total Assets at March31, 2010 and March31, 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

Variable Interest Entities

Variable Interest Entities
	3 Months Ended Mar. 31, 2010
Variable Interest Entities [Abstract]
VARIABLE INTEREST ENTITIES	12 VARIABLE INTEREST ENTITIES The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Certain disclosures are required by sponsors, significant interest holders in variable interest entities and potential variable interest entities. We assess our relationships with potential variable interest entities such as our coal suppliers, natural gas suppliers, coal and gas transporters, and other counterparties in power purchase agreements and joint ventures. In making this assessment, we consider the potential that our contracts or other arrangements provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of the entity, the ability to directly or indirectly make decisions about the entities activities and other factors. We have identified two tolling and purchased power agreements with third parties which represent variable interests. We account for one of these agreements, with an independent power producer, as an operating lease. The agreement has a remaining term of three years. We have examined the risks of the entity including the impact of operations and maintenance, dispatch, financing, fuel costs, remaining useful life and other factors, and have determined that we are not the primary beneficiary of this entity. We have concluded that we do not have the power to direct the activities that would most significantly affect the economic performance of the entity over its remaining life. We also have a purchased power agreement for 236 MW of firm capacity from a gas-fired cogeneration facility, which we account for as a capital lease. The agreement includes no minimum energy requirements over the remaining term of 13years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement. We have approximately $405.9million of required payments over the remaining term of these agreements. We believe that the required lease payments under these contracts will continue to be recoverable in rates. Total capacity and lease payments under these contracts for the period ended March31, 2010 was $14.7million. Our maximum exposure to loss is limited to the capacity payments under the contracts.

Commitments and Contingencies

Commitments and Contingencies
	3 Months Ended Mar. 31, 2010
Commitments and Contingencies [Abstract]
COMMITMENTS AND CONTINGENCIES	13 COMMITMENTS AND CONTINGENCIES Environmental Matters: We periodically review our exposure for remediation costs as evidence becomes available indicating that our liability has changed. Given 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. 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. In addition, pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We have established reserves as deemed appropriate for these indemnification provisions. Income Taxes: Within the next 12months, we believe that our federal and state unrecognized tax benefits may decrease by approximately $12million to $15million as the result of payments on tax obligations.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information
	3 Months Ended Mar. 31, 2010
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	14 SUPPLEMENTAL CASH FLOW INFORMATION During the three months ended March31, 2010, we paid $12.2million in interest, capitalized $13.7 million of interest expense and paid $14.3million in income taxes, net of refunds. During the three months ended March31, 2009, we paid $14.4million in interest, capitalized $19.2million of interest expense and paid $0.8million in income taxes, net of refunds. As of March31, 2010 and March31, 2009, the amount of accounts payable related to capital expenditures was $37.7million and $27.5million, respectively.

Subsequent Event - Sale of Edis

Subsequent Event - Sale of Edison Sault
	3 Months Ended Mar. 31, 2010
Subsequent Event - Sale of Edison Sault [Abstract]
SUBSEQUENT EVENT -- SALE OF EDISON SAULT	15 SUBSEQUENT EVENT SALE OF EDISON SAULT We previously announced that we had reached an agreement to sell Edison Sault to Cloverland Electric Cooperative for approximately $61.5million, which represents a nominal gain. We also announced that we would retain the membership interest in ATC held by Edison Sault. The completion of the sale was contingent upon certain conditions and regulatory approvals. In April2010, we received approval by the MPSC, the last remaining regulatory approval, and the sale was completed on May4, 2010. As of March31, 2010, Edison Sault had approximately $54.5million of property, plant and equipment and $5.9million of net current assets. The investment in ATC retained by us was approximately $38.7million.