WISCONSIN ELECTRIC POWER CO - Quarter Report: 2010 September (Form 10-Q)

Total Facility

Letters
of Credit

Credit Available

Facility
Expiration

(Millions of Dollars)

March 2011

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED INCOME STATEMENTS
(Unaudited)

	Three Months Ended September 30		Nine Months Ended September 30

	2010	2009	2010	2009

	(Millions of Dollars)

Operating Revenues	$ 883.2	$ 738.3	$ 2,594.7	$ 2,450.4

Operating Expenses
Fuel and purchased power	336.8	293.2	875.0	813.0
Cost of gas sold	27.0	26.4	218.7	285.9
Other operation and maintenance	356.1	301.5	1,051.4	926.5
Depreciation and amortization	54.3	66.9	162.1	198.9
Property and revenue taxes	24.6	24.8	72.7	74.6

Total Operating Expenses	798.8	712.8	2,379.9	2,298.9

Amortization of Gain	55.2	57.9	151.8	177.2


Operating Income	139.6	83.4	366.6	328.7

Equity in Earnings of Transmission Affiliate	13.4	13.1	40.0	38.3
Other Income, net	9.5	9.5	25.2	21.8
Interest Expense, net	25.5	24.8	77.1	75.6


Income Before Income Taxes	137.0	81.2	354.7	313.2

Income Taxes	47.4	28.5	124.3	110.2


Net Income	89.6	52.7	230.4	203.0

Preferred Stock Dividend Requirement	0.3	0.3	0.9	0.9


Earnings Available for Common Stockholder	$ 89.3	$ 52.4	$ 229.5	$ 202.1





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

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS

			(Unaudited)
			September 30, 2010	December 31, 2009
			(Millions of Dollars)
Assets

Property, Plant and Equipment
	In service		$ 7,819.6	$ 7,718.0
	Accumulated depreciation		(2,855.6)	(2,822.6)

			4,964.0	4,895.4
	Construction work in progress		660.0	382.6
	Leased facilities, net		1,869.6	959.6

		Net Property, Plant and Equipment	7,493.6	6,237.6

Investments
	Equity investment in transmission affiliate		287.6	276.7
	Other		0.4	0.5

		Total Investments	288.0	277.2

Current Assets
	Cash and cash equivalents		10.7	18.3
	Restricted cash		62.7	194.5
	Accounts receivable		251.5	223.0
	Accounts receivable from related parties		23.7	22.8
	Accrued revenues		146.4	212.8
	Materials, supplies and inventories		347.0	321.5
	Prepayments		84.3	122.2
	Regulatory assets		47.0	48.5
	Other		27.5	25.5

		Total Current Assets	1,000.8	1,189.1

Deferred Charges and Other Assets
	Regulatory assets		1,033.3	1,014.6
	Other		161.3	152.7

		Total Deferred Charges and Other Assets	1,194.6	1,167.3

Total Assets			$ 9,977.0	$ 8,871.2




Capitalization and Liabilities

Capitalization
	Common equity		$ 3,020.1	$ 2,804.2
	Preferred stock		30.4	30.4
	Long-term debt		1,970.5	1,969.5
	Capital lease obligations		2,064.7	1,111.3

		Total Capitalization	7,085.7	5,915.4

Current Liabilities
	Long-term debt and capital lease obligations due currently		19.0	12.0
	Short-term debt		44.5	92.0
	Subsidiary note payable to Wisconsin Energy		28.0	28.2
	Accounts payable		208.1	207.0
	Accounts payable to related parties		88.4	79.9
	Regulatory liabilities		65.4	220.8
	Other		265.6	229.5

		Total Current Liabilities	719.0	869.4

Deferred Credits and Other Liabilities
	Regulatory liabilities		663.7	591.3
	Deferred income taxes - long-term		842.2	833.8
	Pension and other benefit obligations		398.8	374.2
	Other		267.6	287.1

		Total Deferred Credits and Other Liabilities	2,172.3	2,086.4

Total Capitalization and Liabilities			$ 9,977.0	$ 8,871.2





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

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

				Nine Months Ended September 30

				2010	2009

				(Millions of Dollars)
Operating Activities
	Net income			$ 230.4	$ 203.0
	Reconciliation to cash
		Depreciation and amortization		168.2	206.3
		Amortization of gain		(151.8)	(177.2)
		Equity in earnings of transmission affiliate		(40.0)	(38.3)
		Distributions from transmission affiliate		32.4	30.3
		Deferred income taxes and investment tax credits, net		(13.2)	81.7
		Contributions to benefit plans		-	(283.8)
		Change in -	Accounts receivable and accrued revenues	23.3	102.2
			Inventories	(25.5)	(24.3)
			Other current assets	42.1	52.4
			Accounts payable	1.7	(95.8)
			Accrued income taxes, net	14.2	24.9
			Deferred costs, net	19.5	34.6
			Other current liabilities	20.2	10.3
		Other, net		41.3	(16.1)

Cash Provided by Operating Activities				362.8	110.2

Investing Activities
	Capital expenditures			(396.9)	(349.1)
	Investment in transmission affiliate			(3.5)	(15.8)
	Change in restricted cash			131.8	149.5
	Other, net			(29.2)	(17.4)

Cash Used in Investing Activities				(297.8)	(232.8)

Financing Activities
	Dividends paid on common stock			(134.7)	(134.7)
	Dividends paid on preferred stock			(0.9)	(0.9)
	Retirement and repurchase of long-term debt			-	(147.0)
	Change in total short-term debt			(47.7)	384.0
	Capital contribution from parent			100.0	-
	Other, net			10.7	1.1

Cash (Used in) Provided by Financing Activities				(72.6)	102.5


Change in Cash and Cash Equivalents				(7.6)	(20.1)

Cash and Cash Equivalents at Beginning of Period				18.3	28.4


Cash and Cash Equivalents at End of Period				$ 10.7	$ 8.3





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

WISCONSIN ELECTRIC POWER COMPANY
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 2009 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary for 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, 2010 are not necessarily indicative of the results which may be expected for the entire fiscal year 2010 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Amendments to Variable Interest Entity Consolidation Guidance: In June 2009, the Financial Accounting Standards Board 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 November 15, 2009. We adopted these provisions on January 1, 2010. This adoption did not have any impact on our financial condition, results of operations or cash flows. See Note 11 -- Variable Interest Entities for required disclosures.

3 -- COMMON EQUITY

Share-Based Compensation Expense: For a description of share-based compensation, including Wisconsin Energy stock options, restricted stock and performance units, see Note I -- 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 the terms of outstanding Wisconsin Energy stock options held by our employees during the period.

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

	Three Months Ended September 30		Nine Months Ended September 30

	2010	2009	2010	2009

	(Millions of Dollars)

Stock options	$1.8	$2.5	$5.2	$7.4
Performance units	9.7	5.1	19.7	8.6
Restricted stock	0.2	0.1	0.6	0.3

Share-based compensation expense	$11.7	$7.7	$25.5	$16.3




Related Tax Benefit	$4.6	$3.2	$10.2	$6.6

Stock Option Activity: During the first nine months of 2010, the Compensation Committee granted 257,350 Wisconsin Energy stock options to our employees that had an estimated fair value of $6.72 per share. During the first nine months of 2009, the Compensation Committee granted 1,129,315 Wisconsin Energy stock options to our employees that had an estimated fair value of $8.01 per share. The following assumptions were used to value the Wisconsin Energy 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 Wisconsin Energy's historical experience.

The following is a summary of our employees' Wisconsin Energy stock option activity for the three and nine months ended September 30, 2010:

			Weighted-
		Weighted-	Average	Aggregate
		Average	Remaining	Intrinsic
	Number of	Exercise	Contractual Life	Value
Stock Options	Options	Price	(Years)	(Millions)


Outstanding as of July 1, 2010	7,323,009	$40.28
Granted	-	$ -
Exercised	(899,123)	$31.39
Forfeited	-	$ -

Outstanding as of September 30, 2010	6,423,886	$41.53




Outstanding as of January 1, 2010	8,237,428	$38.95
Granted	257,350	$49.84
Exercised	(2,065,892)	$32.29
Forfeited	(5,000)	$45.70

Outstanding as of September 30, 2010	6,423,886	$41.53	6.0	$104.5




Exercisable as of September 30, 2010	3,836,946	$38.70	4.8	$73.3

The intrinsic value of Wisconsin Energy options exercised by our employees was $22.6 million and $43.6 million for the three and nine months ended September 30, 2010, and $2.5 million and $3.7 million for the same periods in 2009, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $66.7 million and $5.7 million for the nine months ended September 30, 2010 and 2009, respectively. The actual tax benefit realized for the tax deductions from option exercises during the same periods was approximately $17.4 million and $1.5 million, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees that were outstanding as of September 30, 2010:

	Options Outstanding			Options Exercisable

		Weighted-Average			Weighted-Average

			Remaining			Remaining
			Contractual			Contractual
	Number of	Exercise	Life	Number of	Exercise	Life
Range of Exercise Prices	Options	Price	(Years)	Options	Price	(Years)


$20.39 to $25.41	281,270	$24.04	1.7	281,270	$24.04	1.7
$33.44 to $39.48	2,355,598	$35.88	4.3	2,355,598	$35.88	4.3
$42.22 to $49.84	3,787,018	$46.34	7.4	1,200,078	$47.70	6.3

	6,423,886	$41.53	6.0	3,836,946	$38.70	4.8

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the nine months ended September 30, 2010. There was no activity related to non-vested stock options during the third quarter of 2010.

		Weighted-
		Average
	Number of	Fair
Non-Vested Stock Options	Options	Value


Non-vested as of January 1, 2010	3,409,280	$8.73
Granted	257,350	$6.72
Vested	(1,074,690)	$8.72
Forfeited	(5,000)	$8.53

Non-vested as of September 30, 2010	2,586,940	$8.53

As of September 30, 2010, our total compensation costs related to non-vested Wisconsin Energy stock options not yet recognized was approximately $3.3 million, which is expected to be recognized over the next 12 months on a weighted-average basis.

Restricted Shares: The Compensation Committee has also approved Wisconsin Energy restricted stock grants to certain of our key employees. These awards have a three-year vesting period, with, typically, one-third of the award vesting on each anniversary of the grant date. During the vesting period, restricted share recipients have voting rights and are entitled to dividends in the same manner as other shareholders.

The following restricted stock activity related to our employees occurred during the three and nine months ended September 30, 2010:

		Weighted-
		Average
	Number of	Grant Date
Restricted Shares	Shares	Fair Value


Outstanding as of July 1, 2010	85,993
Granted	-	$ -
Released	(1,924)	$29.13
Forfeited	-	$ -

Outstanding as of September 30, 2010	84,069




Outstanding as of January 1, 2010	57,999
Granted	32,505	$49.55
Released	(6,375)	$27.64
Forfeited	(60)	$49.55

Outstanding as of September 30, 2010	84,069

Wisconsin Energy records the market value of the restricted stock awards on the date of grant. We then amortize our share of allocated expense over the vesting period of the awards. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was $0.1 million and $0.3 million for the three and nine months ended September 30, 2010 and 2009, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was zero and $0.1 million for the three and nine month periods ended September 30, 2010 and 2009.

As of September 30, 2010, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $1.6 million, which is expected to be recognized over the next 28 months on a weighted-average basis.

Performance Units: In January 2010 and 2009, the Compensation Committee awarded 260,310 and 309,310 Wisconsin Energy performance units, respectively, to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units which will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's common stock over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash. We are accruing our share of compensation costs over the three-year period based on our estimate of the final expected value of the award. Performance units earned as of December 31, 2009 and 2008 vested and were settled during the first quarter of 2010 and 2009, and had a total intrinsic value of $9.3 million and $7.9 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $3.2 million and $2.9 million, respectively. As of September 30, 2010, total compensation cost related to performance units not yet recognized was approximately $29.4 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Equity Contribution: Our capitalization reflects the impact of a $100.0 million equity contribution from Wisconsin Energy during the third quarter of 2010.

Restrictions: Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. See Note I -- Common Equity in our 2009 Annual Report on Form 10-K for additional information on these and other restrictions.

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. During the nine months ended September 30, 2010 and 2009, total comprehensive income was equal to net income.

4 -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

On February 2, 2010, Oak Creek expansion Unit 1 (OC 1) was placed in service. Prior to December 31, 2009, certain common facilities associated with the Oak Creek expansion were placed in service. We now have care, custody and control of OC 1 and will operate and maintain it over the 30 year life of the lease. As a result of the commercial operation of OC 1, in February 2010, we recorded an additional capital lease asset and capital lease obligation related to the Oak Creek expansion totaling approximately $1.0 billion. The lease payments are expected to be recovered through our rates, as supported by the Wisconsin 2001 Leased Generation Law. The total obligation under the capital lease for OC 1, including the common facilities, was $1.3 billion as of September 30, 2010 and will decrease to zero over the remaining life of the contract.

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 Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp., for our net book value, including working capital. In March 2010, the agreement became effective and we are in the process of receiving regulatory approvals. The completion of the sale is subject to approval by applicable regulatory bodies, including the FERC, Public Service Commission of Wisconsin (PSCW) and Michigan Public Service Commission (MPSC). In June 2010, we received approval for the sale from FERC. If approved by the remaining regulatory bodies, we expect the sale to close by the end of 2010 and to realize proceeds of between $40 million and $45 million depending on the working capital balances and our level of capital investment in the unit prior to the sale.

6 -- 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 Over-the-Counter (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 instrument's 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 September 30, 2010

	Level 1	Level 2	Level 3	Total

	(Millions of Dollars)
Assets:
Restricted Cash	$62.7	$ -	$ -	$62.7
Derivatives	2.3	3.3	10.4	16.0

Total	$65.0	$3.3	$10.4	$78.7

Liabilities:
Derivatives	$8.0	$5.1	$ -	$13.1

Total	$8.0	$5.1	$ -	$13.1

Recurring Fair Value Measures	As of December 31, 2009

	Level 1	Level 2	Level 3	Total

	(Millions of Dollars)
Assets:
Restricted Cash	$194.5	$ -	$ -	$194.5
Derivatives	0.6	3.3	5.8	9.7

Total	$195.1	$3.3	$5.8	$204.2

Liabilities:
Derivatives	$4.2	$2.4	$ -	$6.6

Total	$4.2	$2.4	$ -	$6.6

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents the remaining funds to be distributed to customers resulting from the net proceeds received from the sale of the Point Beach Nuclear Power Plant (Point Beach). Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be

observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

The following table summarizes the fair value of derivatives classified as Level 3 in the fair value hierarchy:

	Quarter to Date		Year to Date

	2010	2009	2010	2009

	(Millions of Dollars)

Beginning Balance	$15.9	$15.4	$5.8	$8.8
Realized and unrealized gains (losses)	-	-	-	-
Purchases, issuances and settlements	(5.5)	(5.3)	4.6	1.3
Transfers in and/or out of Level 3	-	-	-	-

Balance as of September 30	$10.4	$10.1	$10.4	$10.1




Change in unrealized gains (losses) relating to instruments still held as of September 30	$ -	$ -	$ -	$ -

Derivative instruments reflected in Level 3 of the hierarchy include MISO Financial Transmission Rights (FTRs) that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet. See Note 7 -- Derivative Instruments for further information on the offset to regulatory assets and liabilities.

The carrying amount and estimated fair value of certain of our recorded financial instruments are as follows:

	September 30, 2010		December 31, 2009

Financial Instruments	Carrying Amount	Fair Value	Carrying Amount	Fair Value

	(Millions of Dollars)

Preferred stock, no redemption required	$30.4	$23.0	$30.4	$20.2
Long-term debt including current portion	$1,987.0	$2,255.3	$1,987.1	$2,088.2

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.

7 -- 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. 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 derivative's 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 September 30, 2010, we recognized $17.6 million in regulatory assets and $14.8 million in regulatory liabilities related to derivatives in comparison to $11.6 million in regulatory assets and $9.3 million in regulatory liabilities as of December 31, 2009.

We record our current derivative assets on the balance sheet in Other current assets and the current portion of the liabilities in Other current liabilities. The long-term portion of our derivative assets of $1.0 million is recorded in Other deferred charges and other assets, and the long-term portion of our derivative liabilities of $0.8 million is recorded in Other deferred credits and other liabilities. Our Consolidated Condensed Balance Sheets as of September 30, 2010 and December 31, 2009 include:

	September 30, 2010		December 31, 2009

	Derivative	Derivative	Derivative	Derivative
	Asset	Liability	Asset	Liability

	(Millions of Dollars)

Natural Gas	$1.4	$13.1	$1.2	$6.6
Fuel Oil	2.3	-	0.6	-
FTRs	10.4	-	5.8	-
Coal	1.9	-	2.1	-

Total	$16.0	$13.1	$9.7	$6.6

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 gains (losses) for the three and nine months ended September 30, 2010 and 2009 were as follows:

	Three Months Ended September 30, 2010		Three Months Ended September 30, 2009

	Volume	Gains (Losses)	Volume	Gains (Losses)

		(Millions of Dollars)		(Millions of Dollars)

Natural Gas	8.5 million Dth	($4.6)	12.0 million Dth	($20.4)
Power	65,040 MWh	(0.5)	8,400 MWh	-
Fuel Oil	2.3 million gallons	(0.1)	2.1 million gallons	(0.5)
FTRs	6,584 MW	4.4	6,561 MW	1.3

Total		($0.8)		($19.6)

	Nine Months Ended September 30, 2010		Nine Months Ended September 30, 2009

	Volume	Gains (Losses)	Volume	Gains (Losses)

		(Millions of Dollars)		(Millions of Dollars)

Natural Gas	30.0 million Dth	($18.7)	35.5 million Dth	($59.0)
Power	224,640 MWh	(0.5)	23,520 MWh	(0.6)
Fuel Oil	6.0 million gallons	(0.1)	5.1 million gallons	(2.3)
FTRs	18,673 MW	16.2	21,132 MW	6.1

Total		($3.1)		($55.8)

As of September 30, 2010 and December 31, 2009, we have posted collateral of $10.7 million and $6.6 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in Other current assets.

8 -- BENEFITS

The components of our net periodic pension and Other Post-Retirement Employee Benefits (OPEB) costs for the three and nine months ended September 30, 2010 and 2009 were as follows:

	Pension Costs

	Three Months Ended September 30		Nine Months Ended September 30

Benefit Plan Cost Components	2010	2009	2010	2009

	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$5.6	$5.4	$16.6	$16.1
Interest cost	14.8	15.5	44.3	46.4
Expected return on plan assets	(14.9)	(18.3)	(44.7)	(54.8)
Amortization of:
Prior service cost	0.5	0.5	1.6	1.6
Actuarial loss	4.7	3.2	14.1	9.6

Net Periodic Benefit Cost	$10.7	$6.3	$31.9	$18.9

	OPEB Costs

	Three Months Ended September 30		Nine Months Ended September 30

Benefit Plan Cost Components	2010	2009	2010	2009

	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$2.7	$2.0	$8.0	$6.1
Interest cost	4.3	4.1	13.0	12.4
Expected return on plan assets	(2.3)	(2.2)	(6.9)	(6.7)
Amortization of:
Transition obligation	0.1	0.1	0.3	0.2
Prior service credit	(3.0)	(3.2)	(8.9)	(9.5)
Actuarial loss	2.1	1.4	6.2	4.2

Net Periodic Benefit Cost	$3.9	$2.2	$11.7	$6.7

Postemployment Benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $11.5 million as of September 30, 2010 and $10.8 million as of December 31, 2009.

9 -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties. As of September 30, 2010, we had the following guarantees:

Maximum Potential
Future Payments	Outstanding	Liability Recorded

(Millions of Dollars)

$2.8	$0.1	$ -

We are subject to the potential retrospective premiums that could be assessed under our insurance program.

10 -- SEGMENT INFORMATION

Summarized financial information concerning our operating segments for the three and nine months ended September 30, 2010 and 2009 is shown in the following table:

	Operating Segments

	Electric	Gas	Steam	Total

	(Millions of Dollars)
Three Months Ended


September 30, 2010
Operating Revenues (a)	$827.2	$50.1	$5.9	$883.2
Operating Income (Loss)	$148.8	($6.3)	($2.9)	$139.6

September 30, 2009
Operating Revenues (a)	$682.7	$49.8	$5.8	$738.3
Operating Income (Loss)	$90.6	($5.7)	($1.5)	$83.4

Nine Months Ended


September 30, 2010
Operating Revenues (a)	$2,232.7	$334.5	$27.5	$2,594.7
Operating Income	$342.0	$23.0	$1.6	$366.6

September 30, 2009
Operating Revenues (a)	$2,012.6	$409.6	$28.2	$2,450.4
Operating Income	$291.4	$33.5	$3.8	$328.7

(a)	We account for all intersegment revenues at tariff rates established by the PSCW. Intersegment revenues were not material.

As of September 30, 2010, our total assets increased by approximately $1.1 billion as compared to December 31, 2009, primarily because of the commencement of commercial operation of OC 1 in February 2010, at which time we recorded an additional capital lease asset of approximately $1.0 billion.

11 -- 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 13 years. 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 $376.3 million 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 nine months ended September 30, 2010 were $49.6 million. Our maximum exposure to loss is limited to the capacity payments under the contracts.

12 -- 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.

Indemnifications: In connection with the sale of Point Beach, we agreed to provide the buyer with indemnification provisions customary to transactions involving the sale of nuclear assets.

Income Taxes: During the first nine months of 2010, our federal unrecognized tax benefits decreased by $12.3 million as the result of payment of a tax obligation for a prior year.

13 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the nine months ended September 30, 2010, we paid $48.2 million in interest, net of amounts capitalized, and $107.4 million in income taxes, net of refunds. During the nine months ended September 30, 2009, we paid $49.8 million in interest, net of amounts capitalized, and $0.9 million in income taxes, net of refunds.

As of September 30, 2010 and 2009, the amount of accounts payable related to capital expenditures was $16.0 million.

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

RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 2010

EARNINGS

We recorded net income of $89.6 million for the third quarter of 2010, an increase of $36.9 million, or 70.0%, from the third quarter of 2009. Our operating income was $139.6 million for the third quarter of 2010, an increase of $56.2 million, or 67.4%, from the third quarter of 2009. A more detailed analysis of our financial results follows.

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the third quarter of 2010 with the third quarter of 2009, including favorable (better (B)) or unfavorable (worse (W)) variances:

	Three Months Ended September 30

	Electric Revenues			MWh Sales

Electric Utility Operations	2010	B (W)	2009	2010	B (W)	2009

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$329.3	$86.8	$242.5	2,508.5	524.6	1,983.9
Small Commercial/Industrial	251.8	26.6	225.2	2,414.4	137.5	2,276.9
Large Commercial/Industrial	188.0	25.0	163.0	2,703.6	268.4	2,435.2
Other - Retail	5.0	0.1	4.9	35.6	0.3	35.3

Total Retail	774.1	138.5	635.6	7,662.1	930.8	6,731.3
Wholesale - Other	35.6	10.5	25.1	536.6	296.3	240.3
Resale - Utilities	10.8	3.1	7.7	193.2	(89.3)	282.5
Other Operating Revenues	6.7	(7.6)	14.3	-	-	-

Total	$827.2	$144.5	$682.7	8,391.9	1,137.8	7,254.1




Weather -- Degree Days (a)
Heating (127 Normal)				118	(6)	124
Cooling (517 Normal)				733	392	341

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our electric utility operating revenues increased by $144.5 million, or 21.2%, when compared to the third quarter of 2009. The most significant factors that caused the change in revenues were:

Favorable weather that increased electric revenues by an estimated $94.5 million as compared to the third quarter of 2009.
Net pricing increases totaling $44.0 million related to Wisconsin and Michigan rate orders that became effective in 2010. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.
Net economic growth that increased electric revenues by an estimated $12.2 million as compared to the third quarter of 2009.
2010 pricing increases totaling approximately $2.7 million, reflecting the reduction of Point Beach bill credits to retail customers.

As measured by cooling degree days, the third quarter of 2010 was 115.0% warmer than the same period in 2009 and 41.8% warmer than normal. Collectively, retail sales to our residential and small commercial and industrial customers, who are more weather sensitive, increased by 15.5%. Sales to our large commercial and industrial customers increased by 11.0% during the third quarter of 2010 as compared to the same period in 2009, primarily because of an improving economy. Electric sales to our largest customers, two iron ore mines, increased significantly for the quarter. If these sales are excluded, sales to our large commercial and industrial customers increased by 4.1% for the third quarter of 2010 as compared to the third quarter of 2009. The $7.6 million decline in Other Operating Revenues primarily relates to regulatory amortizations during the third quarter of 2010 as compared to the same period in 2009.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $43.6 million, or 14.9%, when compared to the third quarter of 2009. This increase was primarily caused by the 15.7% increase in total MWh sales, partially

offset by a 0.9% decrease in the average cost/MWh between periods. The average cost/MWh was comparable between periods because of a 14.8% increase in generation from our lower cost coal units, which was sufficient to offset the impact of a 5.9% increase in coal and transportation costs and the increased cost of purchased power utilized as a result of the increased sales.

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 2010 with the third quarter of 2009. 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 operating revenues increased by $0.3 million, or 0.6%, primarily because of higher natural gas prices.

	Three Months Ended September 30

	2010	B (W)	2009

	(Millions of Dollars)

Gas Operating Revenues	$50.1	$0.3	$49.8
Cost of Gas Sold	27.0	(0.6)	26.4

Gross Margin	$23.1	($0.3)	$23.4

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2010 with the third quarter of 2009:

	Three Months Ended September 30

	Gross Margin			Therm Deliveries

Gas Utility Operations	2010	B (W)	2009	2010	B (W)	2009

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$15.2	($0.4)	$15.6	19.3	(3.1)	22.4
Commercial/Industrial	3.9	(0.3)	4.2	13.4	(1.6)	15.0
Interruptible	0.1	-	0.1	0.8	0.2	0.6

Total Retail	19.2	(0.7)	19.9	33.5	(4.5)	38.0
Transported Gas	3.6	0.5	3.1	74.3	14.3	60.0
Other	0.3	(0.1)	0.4	-	-	-

Total	$23.1	($0.3)	$23.4	107.8	9.8	98.0




Weather -- Degree Days (a)
Heating (127 Normal)				118	(6)	124

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our gas margin is seasonal and is primarily driven by the heating needs of our customers. The third quarter gas margin is historically the lowest of the year because of the lack of heating load. Our gas margin decreased by $0.3 million, or 1.3%, when compared to the third quarter of 2009.

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $54.6 million, or approximately 18.1%, when compared to the third quarter of 2009. The 2010 PSCW rate case order allowed for pricing increases related to regulatory items including PTF lease costs, bad debt expense and amortization of other deferred costs. We estimate that these items were approximately $18.2 million higher in the third quarter of 2010 as compared to the same period in 2009. In addition, operation and maintenance expenses at our power plants increased by approximately $18.1 million primarily because of the operation of OC 1, which was placed in service in February 2010, and higher maintenance costs at our other power plants.

Depreciation and Amortization Expense

Our depreciation and amortization expense decreased by $12.6 million, or approximately 18.8%, when compared to the third quarter of 2009 primarily because of new depreciation rates that were implemented in connection with the 2010 PSCW rate case order. The new depreciation rates generally reflect longer lives for our utility assets.

Amortization of Gain

In connection with the September 2007 sale of Point Beach, we reached agreements with our regulators to allow for the net gain on the sale to be used for the benefit of our customers. The majority of the benefits are being returned to customers in the form of bill credits. The net gain was originally recorded as a regulatory liability, and it is being amortized to the income statement as we issue bill credits to our customers. When the bill credits are issued to customers, we transfer cash from the restricted accounts to the unrestricted accounts, adjusted for taxes. During the third quarter of 2010 and 2009, the Amortization of Gain was $55.2 million and $57.9 million, respectively. We expect that all remaining bill credits will be issued by December 31, 2010.

Interest Expense, net

	Three Months Ended September 30

Interest Expense, net	2010	B (W)	2009

	(Millions of Dollars)

Gross Interest Costs	$29.1	($2.5)	$26.6
Less: Capitalized Interest	3.6	1.8	1.8

Interest Expense, net	$25.5	($0.7)	$24.8

Our gross interest costs increased by $2.5 million, or 9.4%, when compared to the third quarter of 2009 primarily because of higher long-term debt balances. Our capitalized interest increased by $1.8 million primarily because of increased capital expenditures related to our Oak Creek Air Quality Control System (AQCS) project during the third quarter of 2010 as compared to the same period in 2009. As a result, our net interest expense increased by $0.7 million, or 2.8%, as compared to the third quarter of 2009.

Income Taxes

For the third quarter of 2010, our effective tax rate was 34.6% compared to 35.1% for the third quarter of 2009. For additional information, see Note G -- Income Taxes in our 2009 Annual Report on Form 10-K.

RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2010

EARNINGS

We recorded net income of $230.4 million for the first nine months of 2010, an increase of $27.4 million, or 13.5%, from the first nine months of 2009. Our operating income was $366.6 million for the first nine months of 2010, an increase of $37.9 million, or 11.5%, from the first nine months of 2009. The increase in operating income was primarily caused by favorable weather during 2010, partially offset by unfavorable recoveries of revenues associated with fuel and purchased power and milder winter weather in 2010. During the first nine months of 2010, we experienced unfavorable fuel recoveries of approximately $64 million. During the same period in 2009, we experienced favorable fuel recoveries of approximately $2 million. Although we received a fuel order from the PSCW in March 2010 allowing us to increase our rates on an interim basis, we expect to be in an unfavorable fuel recovery position for 2010. For additional information on the fuel order, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters - 2010 Fuel Recovery Request.

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 2010 with the first nine months of 2009, including favorable (better (B)) or unfavorable (worse (W)) variances:

	Nine Months Ended September 30

	Electric Revenues			MWh Sales

Electric Utility Operations	2010	B (W)	2009	2010	B (W)	2009

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$842.1	$114.2	$727.9	6,383.7	484.9		5,898.8
Small Commercial/Industrial	699.3	42.4	656.9	6,708.4	159.4		6,549.0
Large Commercial/Industrial	514.4	65.8	448.6	7,526.5	748.0		6,778.5
Other - Retail	15.8	0.4	15.4	111.8	(0.9)		112.7

Total Retail	2,071.6	222.8	1,848.8	20,730.4	1,391.4		19,339.0
Wholesale - Other	107.1	20.0	87.1	1,572.9	450.8		1,122.1
Resale - Utilities	34.2	2.7	31.5	869.8	(104.3)		974.1
Other Operating Revenues	19.8	(25.4)	45.2	-	-		-

Total	$2,232.7	$220.1	$2,012.6	23,173.1	1,737.9		21,435.2




Weather -- Degree Days (a)
Heating (4,320 Normal)				3,933	(595)		4,528
Cooling (688 Normal)				941	466		475

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our electric utility operating revenues increased by $220.1 million, or 10.9%, when compared to the first nine months of 2009. The most significant factors that caused the change in revenues were:

Favorable weather that increased electric revenues by an estimated $100.6 million as compared to the first nine months of 2009.
Net pricing increases totaling $81.2 million related to Wisconsin and Michigan rate orders that became effective in 2010. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.
Net economic growth that increased electric revenues by an estimated $34.9 million as compared to the first nine months of 2009.
2010 pricing increases totaling approximately $25.4 million, reflecting the reduction of Point Beach bill credits to retail customers.

As measured by cooling degree days, the first nine months of 2010 were 98.1% warmer than the same period in 2009 and 36.8% warmer than normal. Collectively, retail sales to our residential and small commercial and industrial customers, who are more weather sensitive, increased by 5.2%. Sales to our large commercial and industrial customers increased by 11.0% during the first nine months of 2010 as compared to the same period in 2009, primarily because of an improving economy. Electric sales to our largest customers, two iron ore mines, increased significantly for the first nine months of the year. If these sales are excluded, sales to our large commercial and industrial customers increased by 3.9% for the first nine months of 2010 as compared to the first nine months of 2009. The $25.4 million decline in Other Operating Revenues primarily relates to regulatory amortizations during the first nine months of 2010 as compared to the same period in 2009.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $62.0 million, or 7.6%, when compared to the first nine months of 2009. This increase was primarily caused by the 8.1% increase in total MWh sales, partially offset by a 0.4% decrease in the average cost/MWh between periods. The average cost/MWh was comparable between periods because of a 12.7% increase in generation from our lower cost coal units, which was sufficient to offset the impact of a 5.4% increase in coal and transportation costs and the increased cost of purchased power utilized as a result of the increased sales.

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 2010 with the first nine months of 2009. 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 operating revenues decreased by $75.1 million, or 18.3%, primarily because of lower natural gas prices and milder weather.

	Nine Months Ended September 30

	2010	B (W)	2009

	(Millions of Dollars)

Gas Operating Revenues	$334.5	($75.1)	$409.6
Cost of Gas Sold	218.7	67.2	285.9

Gross Margin	$115.8	($7.9)	$123.7

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2010 with the first nine months of 2009:

	Nine Months Ended September 30

	Gross Margin			Therm Deliveries

Gas Utility Operations	2010	B (W)	2009	2010	B (W)	2009

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$77.3	($6.1)	$83.4	211.9	(28.9)	240.8
Commercial/Industrial	24.3	(3.6)	27.9	121.5	(21.6)	143.1
Interruptible	0.4	-	0.4	4.0	(0.2)	4.2

Total Retail	102.0	(9.7)	111.7	337.4	(50.7)	388.1
Transported Gas	11.5	1.4	10.1	225.7	6.3	219.4
Other	2.3	0.4	1.9	-	-	-

Total	$115.8	($7.9)	$123.7	563.1	(44.4)	607.5




Weather -- Degree Days (a)
Heating (4,320 Normal)				3,933	(595)	4,528

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our gas margin decreased by $7.9 million, or approximately 6.4%, when compared to the first nine months of 2009 primarily because of a decline in sales volumes as a result of warmer winter weather in 2010 as compared to 2009. As measured by heating degree days, the first nine months of 2010 were 13.1% warmer than the same period in 2009 and 9.0% warmer than normal.

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $124.9 million, or approximately 13.5%, when compared to the first nine months of 2009. The 2010 PSCW rate case order allowed for pricing increases related to regulatory items including PTF lease costs, bad debt expense and amortization of other deferred costs. We estimate that these items were approximately $53.2 million higher in the first nine months of 2010 as compared to the same period in 2009. In addition, operation and maintenance expenses at our power plants increased by approximately $42.6 million primarily because of the operation of OC 1, which was placed in service in February 2010, and higher maintenance costs at our other power plants.

Depreciation and Amortization Expense

Our depreciation and amortization expense decreased by $36.8 million, or approximately 18.5%, when compared to the first nine months of 2009 primarily because of new depreciation rates that were implemented in connection with the 2010 PSCW rate case order. The new depreciation rates generally reflect longer lives for our utility assets.

Amortization of Gain

During the first nine months of 2010 and 2009, the Amortization of Gain was $151.8 million and $177.2 million, respectively. For 2010, we expect to see a reduction in the Amortization of Gain of approximately $34.6 million as compared to 2009 because of the scheduled decrease in Point Beach bill credits. We expect that all remaining Point Beach bill credits will be issued by December 31, 2010.

Other Income, net

Other income, net increased by $3.4 million, or approximately 15.6%, when compared to the first nine months of 2009 primarily because of an increase in Allowance for Funds Used During Construction (AFUDC) - Equity related to the construction of our Oak Creek AQCS project.

Interest Expense, net

	Nine Months Ended September 30

Interest Expense, net	2010	B (W)	2009

	(Millions of Dollars)

Gross Interest Costs	$86.2	($6.1)	$80.1
Less: Capitalized Interest	9.1	4.6	4.5

Interest Expense, net	$77.1	($1.5)	$75.6

Our gross interest costs increased by $6.1 million, or 7.6%, when compared to the first nine months of 2009 primarily because of higher long-term debt balances. Our capitalized interest increased by $4.6 million primarily because of increased capital expenditures related to our Oak Creek AQCS project during the first nine months of 2010 as compared to the same period in 2009. As a result, our net interest expense increased by $1.5 million, or 2.0%, as compared to the first nine months of 2009.

Income Taxes

For the first nine months of 2010, our effective tax rate was 35.0% compared to 35.2% for the first nine months of 2009. For additional information, see Note G -- Income Taxes in our 2009 Annual Report on Form 10-K. We expect our 2010 annual effective tax rate to be between 35.0% and 36.0%.

LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS

The following summarizes our cash flows during the first nine months of 2010 and 2009:

	Nine Months Ended September 30

	2010	2009

	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$362.8	$110.2
Investing Activities	($297.8)	($232.8)
Financing Activities	($72.6)	$102.5

Operating Activities

Cash provided by operating activities was $362.8 million during the nine months ended September 30, 2010, which was $252.6 million higher than the same period in 2009. This increase was primarily due to lower contributions to benefit plans, offset in part by higher cash taxes. During 2009, we contributed $283.8 million to Wisconsin Energy's benefit plans. No such contributions were required in the first nine months of 2010. Our tax payments increased by $106.5 million primarily because of lower deferred income taxes as compared to 2009.

Investing Activities

Cash used in investing activities was $297.8 million during the nine months ended September 30, 2010, which was $65.0 million higher than the same period in 2009. The increase in cash used in investing activities primarily reflects an increase in capital expenditures and a reduction in the release of restricted cash related to the Point Beach bill credits. During the first nine months of 2010, our capital expenditures increased by $47.8 million primarily because of the commencement of construction of our Glacier Hills Wind Park in May 2010. During the first nine months of 2010, we released $17.7 million less from restricted cash as compared to the same period in 2009.

Financing Activities

Cash used in financing activities was $72.6 million during the nine months ended September 30, 2010 compared to $102.5 million provided by financing activities during the same period in 2009. The decrease in financing cash flows is primarily related to changes in our debt levels. During the first nine months of 2010, we decreased our debt levels by $47.7 million compared to an increase of $237.0 million in our debt levels during the same period in 2009. Partially offsetting this decrease in financing cash flows was a $100.0 million capital contribution from Wisconsin Energy during the first nine months of 2010.

CAPITAL RESOURCES AND REQUIREMENTS
Liquidity

We anticipate meeting our capital requirements during the remaining three months of 2010 primarily through internally generated funds and short-term borrowings, supplemented as necessary by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors, and an equity contribution from our parent. Beyond 2010, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by short-term borrowings, the issuance of debt securities and equity contributions from our parent.

We currently 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 currently believe that we have adequate

capacity to fund our operations for the foreseeable future through our existing borrowing arrangement, access to capital markets and internally generated cash.

We maintain a bank back-up credit facility that provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes.

As of September 30, 2010, we had approximately $473.7 million of available, undrawn lines under our bank back-up credit facility, and approximately $44.5 million of commercial paper outstanding that was supported by the available lines of credit.

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 facility as of September 30, 2010:

We recorded an increase of approximately $1.0 billion to our capital lease obligations in connection with OC 1 being placed in service in February 2010. For additional information, see Note 4 -- Long-Term Debt and Capital Lease Obligations in the Notes to Consolidated Condensed Financial Statements in this report.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of September 30, 2010, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Access to capital markets at a reasonable cost is determined in large part by credit quality. Any change in ratings or ratings outlooks could impact our cost of capital and access to the capital markets.

In July 2010, S&P affirmed our ratings and our stable rating outlook.

In June 2010, Fitch affirmed our ratings and revised our rating outlook from negative to stable. Prior to these actions, Fitch revised its ratings guidelines on corporate and utility preferred securities, which reduced the rating of our Preferred Stock one notch from A to A-.

Subject to other factors affecting the credit markets as a whole, we believe our current 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. 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.

Capital Requirements

Our estimated 2010, 2011 and 2012 capital expenditures reflecting actual costs through September 30, 2010 are as follows:

Capital Expenditures	2010	2011	2012

	(Millions of Dollars)

Renewable	$96.8	$384.7	$179.3
Environmental	229.4	193.9	80.7
Base Spending	300.8	329.1	370.7

Total	$627.0	$907.7	$630.7

Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such as air quality standards, renewable energy standards and electric reliability initiatives that impact us.

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 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 9 -- Guarantees and Note 11 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements in this report.

Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments were approximately $25.0 billion as of September 30, 2010 compared with $21.4 billion as of December 31, 2009. Our total contractual obligations and other commercial commitments as of September 30, 2010 increased compared with December 31, 2009 primarily because of increased capital lease obligations related to OC 1, which was placed in service in February 2010.

FACTORS AFFECTING RESULTS, LIQUIDITY 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 2009 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, Wisconsin Energy's PTF strategy, rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring and competition and other matters.

POWER THE FUTURE

Under Wisconsin Energy's PTF strategy, we expect to meet a significant portion of our future generation needs through the leasing of the Port Washington Generating Station (PWGS) and the Oak Creek expansion. We are leasing the PWGS units and OC 1 from We Power under long-term leases, and we are currently recovering the lease payments in our electric rates. When OC 2 is placed in service, we expect to record a capital lease obligation of approximately $650 million. We expect to recover the OC 2 lease payments in our electric rates. See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2009 Annual Report on Form 10-K for additional information on PTF.

Oak Creek Expansion: OC 1 was placed in service in February 2010. We expect OC 2 to be placed in service during the fourth quarter of 2010; the guaranteed in-service date for OC 2 is November 28, 2010.

RATES AND REGULATORY MATTERS

2010 Wisconsin Rate Case: In March 2009, we initiated rate proceedings with the PSCW. We initially asked the PSCW to approve a rate increase for our Wisconsin retail electric customers of approximately $76.5 million, or 2.8%, and a rate increase for our natural gas customers of approximately $22.1 million, or 3.6%. In addition, we requested increases of approximately $1.4 million, or 5.8%, and approximately $1.3 million, or 6.8%, for our Milwaukee Downtown (Valley) steam utility customers and Milwaukee County steam utility customers, respectively.

In July 2009, we filed supplemental testimony with the PSCW updating our rate increase request for retail electric customers to reflect the impact of lower sales as a result of the decline in the economy. The effect of the change resulted in us increasing our request from $76.5 million to $126.0 million.

In December 2009, the PSCW authorized rate adjustments related to our request to increase electric, natural gas and steam rates. The PSCW approved the following rate adjustments:

An increase of approximately $85.8 million (3.35%) in our retail electric rates, which included a decrease in base fuel revenues of approximately $111.0 million, or a fuel rate component decrease of 13.8%;
A decrease of approximately $2.0 million (0.35%) for natural gas service; and
A decrease of approximately $0.4 million (1.65%) for our Valley steam utility customers and a decrease of approximately $0.1 million (0.47%) for our Milwaukee County steam utility customers.

These rate adjustments became effective January 1, 2010. In addition, the PSCW lowered our authorized return on equity from 10.75% to 10.4%.

The PSCW also made, among others, the following determinations:

New depreciation rates were incorporated into the new base rates approved in the rate case;
Certain regulatory assets that were scheduled to be fully amortized over the next four years are to instead be amortized over the next eight years; and
We will continue to receive AFUDC on 100% of Construction Work in Progress for the environmental control projects at our Oak Creek Power Plant and at Edgewater Generating Unit 5, and on the Glacier Hills Wind Park.

As part of its final decision in the 2010 rate case, the PSCW authorized us to reopen the docket in 2010 to review updated 2011 fuel costs. On September 3, 2010, we filed an application with the PSCW to reopen the docket to review updated 2011 fuel costs and to set rates for 2011 that reflect those costs. We are requesting an increase in 2011 Wisconsin retail electric rates of $38.4 million, or 1.4%, related to the increase in 2011 monitored fuel costs as compared to the level of monitored fuel costs currently embedded in rates. This increase is being driven primarily by an increase in the delivered cost of coal.

2010 Michigan Rate Increase Request: In July 2009, we filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. Michigan law allows utilities, upon the satisfaction of certain conditions, to self-implement a rate increase request, subject to refund with interest. In December 2009, the MPSC approved our modified self-implementation plan to increase electric rates in Michigan by approximately $12 million effective upon commercial operation of OC 1, which occurred on February 2, 2010. On July 1, 2010, the MPSC issued the final order, approving an additional increase of $11.5 million effective July 2, 2010. The combined total increase is $23.5 million annually, or 14.2%. In August 2010, our largest customers, two iron ore mines, filed an appeal with the MPSC regarding this rate order. On October 14, 2010, the MPSC ruled on the mines' appeal and reduced the rate increase by approximately $256,000 annually, effective November 1, 2010.

2010 Fuel Recovery Request: On February 19, 2010, we filed a $60.5 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The increase in fuel and purchased power costs is being driven primarily by increases in the price of natural gas compared to the forecasted prices included in the 2010 PSCW rate case order, changes in the timing of plant outages and increased MISO costs. Effective March 25, 2010, the PSCW approved an annual increase of $60.5 million in Wisconsin retail electric rates on an interim basis. The revenues that we collect are subject to refund with interest at a rate of 10.4%. We expect PSCW review and final approval by the end of 2010.

2009 Fuel Order: We operate under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation of electricity for our retail customers in Wisconsin. Under the current fuel rules, a Wisconsin utility may request an emergency rate increase if projected costs fall outside of a prescribed range of costs which is plus or minus 2% of the fuel rate approved in a general rate proceeding.

In March 2008, we filed a request for an emergency rate increase with the PSCW to recover forecasted increases in fuel and purchased power costs. The PSCW authorized a total increase of $118.9 million. In April 2009, we filed a request with the PSCW to decrease annual Wisconsin retail electric rates by $67.2 million because we forecasted that our monitored fuel cost for 2009 would fall outside the range prescribed by the PSCW and would be less than the fuel cost reflected in then authorized rates. The PSCW approved this request on an interim basis with rates effective May 1, 2009.

The PSCW staff is currently auditing the fuel costs for the year 2009 to determine whether we collected excess revenues as a result of the fuel surcharges that were in place in 2008 and 2009. Under the current fuel rules, if a utility collects excess revenues in a year in which it implemented an emergency fuel surcharge, it is required to refund to customers the over-collected fuel surcharge revenue up to the amount of the excess revenues.

The PSCW staff has issued for comment a memorandum detailing different alternatives for calculating excess revenues. We do not believe the amount to be refunded to customers, if any, should be material. We anticipate a decision in this matter by the end of 2010.

Wisconsin Fuel Rules: Embedded within our base rates is an amount to recover fuel costs. Under the current Wisconsin fuel rules, no adjustments are made to rates under the fuel cost adjustment clause as long as fuel and purchased power costs are expected to be within a band of the costs embedded in current rates for the 12-month period ending December 31. If, however, annual fuel costs are expected to fall outside of the band, and actual costs fall outside of established fuel bands, then we may file for a change in fuel recoveries on a prospective basis.

In June 2006, the PSCW opened a docket (01-AC-224) to consider revisions to the existing fuel rules (Chapter PSC 116). In April 2010, the Wisconsin legislature passed the Fuel Rule Bill, and the Governor signed it in May 2010. Under this bill, the PSCW will be required to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the utility's symmetrical fuel cost tolerance. As part of the new rules, the PSCW needs to establish, among other things, the size of the symmetrical band, define recoverable fuel and purchased power costs and determine how excess revenues should be calculated, if at all. In August 2010, the PSCW proposed new fuel rules pursuant to this legislation, which are subject to review and comment by the Wisconsin legislature. We expect new fuel rules to be effective in 2011.

Wisconsin Electric - Wisconsin Gas Merger: On April 1, 2010, we, along with Wisconsin Gas, filed a joint application with the PSCW to merge Wisconsin Gas into Wisconsin Electric. On September 1, 2010, we, along with Wisconsin Gas, filed a letter with the PSCW to withdraw the joint application because of uncertainty with the Wisconsin Fuel Rules.

Renewable Energy Portfolio: In July 2008, we completed the purchase of rights to a new wind farm site in Central Wisconsin, Glacier Hills Wind Park, and filed a request for a Certificate of Public Convenience and Necessity (CPCN) with the PSCW in October 2008. The PSCW approved the CPCN in January 2010. We currently expect to install 90 wind turbines with a total generating capacity of approximately 162 MW. This project is expected to cost between $360 million and $370 million,

excluding AFUDC. Construction commenced in May 2010, and we anticipate 2012 will be the first full year of operation.

In September 2009, we announced plans to construct a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site. Wood waste and wood shavings will be used to produce approximately 50 MW of renewable electricity and will also support Domtar's sustainable papermaking operations. We believe the biomass plant will be eligible for either the federal production tax credit or the federal 30% investment tax credit. We currently expect to invest approximately $255 million, excluding AFUDC, in the plant and for it to be completed during the fall of 2013, subject to regulatory and other approvals. In March 2010, we filed a request for a Certificate of Authority for the project with the PSCW. We expect the PSCW to approve the Certificate of Authority no later than the first quarter of 2011.

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 of our 2009 Annual Report on Form 10-K for additional information regarding our rates and other regulatory matters.

ELECTRIC TRANSMISSION AND ENERGY MARKETS

MISO: As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the Locational Marginal Price (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 Auction Revenue Rights (ARRs) and FTRs. ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction was completed for the period of June 1, 2010 through May 31, 2011. The resulting ARR valuation and the secured FTRs should mitigate our transmission congestion risk for that period.

ENVIRONMENTAL MATTERS

Proposed New Coal Ash Regulation: We currently have a successful program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Both Wisconsin and Michigan have regulations governing the use and disposal of these materials. Recently, however, the United States Environmental Protection Agency (EPA) issued a draft rule for public comment proposing various scenarios for regulating coal combustion products including classifying coal ash as hazardous waste. If coal ash is classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program. Curtailing our program could result in the loss of a revenue stream that helps to offset the cost of pollution control equipment and the activities necessary to collect the coal ash.

In addition, if coal ash is classified as hazardous waste and we terminate our coal ash utilization program, we could be required to dispose of the coal ash at a significant cost to the Company.

EPA Regulation of Greenhouse Gas Emissions under the Clean Air Act: In December 2009, the EPA issued its endangerment finding related to greenhouse gas emissions, which set in motion a regulatory process that is leading to regulation of greenhouse gas emissions from stationary sources, including electric generating units, absent legislative or other intervention by the Administration or Congress. On March 29, 2010, the EPA finalized its determination of when the Clean Air Act's permitting requirements for emissions from facilities, including electric generating units, would apply to greenhouse gas emissions. The regulation of stationary sources will occur in multiple steps in the coming years, with the first step scheduled to occur on January 2, 2011. The initial step covers sources that are already subject to EPA regulations for pollutants other than greenhouse gas and includes our generating facilities. Several parties have filed for judicial review of some of the EPA's new greenhouse gas rules. Regulation of greenhouse gas emissions from power plants will impact our ability to do maintenance or modify our existing facilities, and permit new facilities.

Clean Air Interstate Rule: The EPA issued the final Clean Air Interstate Rule (CAIR) in March 2005 to facilitate the states in meeting the 8-hour ozone and Fine Particulate Matter standards by addressing the regional transport of Sulfur Dioxide (SO₂) and Nitrogen Oxide (NO_x). In 2008, the U.S. Court of Appeals for the D.C. Circuit invalidated several aspects of CAIR and remanded the rule to the EPA to promulgate a replacement rule.

In July 2010, the EPA proposed a Transport Rule to replace CAIR. The proposed Transport Rule, like CAIR, would establish individual state caps for the emissions of SO₂ and NO_x from electric generating units in the eastern half of the United States, including Michigan and Wisconsin. The CAIR is in effect as of 2009 for NO_x and 2010 for SO₂, but will be replaced with the new requirements of the Transport Rule, if adopted. The Transport Rule may require new reductions in 2012 for NO_x and SO₂ and additional reductions in 2014 for SO₂ for some states, including Wisconsin and Michigan. According to the EPA, the Transport Rule and other actions by States are expected to result in a 71% reduction of SO₂ and a 52% reduction of NO_x emissions from power plants in the eastern United States by 2014 from 2005 emission levels.

We submitted comments on the proposed rule on October 1, 2010. The EPA intends to finalize the rule in mid-2011.

We previously determined that compliance with the NO_x and SO₂ emission reductions requirements under the Consent Decree that we entered into with the EPA in April 2003 would substantially mitigate costs to comply with CAIR and would achieve the levels necessary under at least the first phase of CAIR. The proposed limits under the Transport Rule appear to be more stringent and could result in the need for additional expenditures by 2014.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2009 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

LEGAL MATTERS

Cash Balance Pension Plan: On June 30, 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. Counsel representing the plaintiff is attempting to seek class certification for other similarly situated plaintiffs. The complaint alleges that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of the Employee Retirement Income Security Act of 1974 (ERISA) and are owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. On September 6, 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant. The plaintiff has not specified the amount of relief he is seeking. An adverse outcome of this lawsuit could have a material adverse effect on Plan funding and expense and our results of operations. Although we are currently unable to predict the final outcome or impact of this litigation, we are aware that a court in a similar lawsuit filed in Wisconsin found that the interest crediting rates applied by the pension plan involved in that case were not in compliance with ERISA.

NUCLEAR OPERATIONS

Used Nuclear Fuel Storage and Disposal: The Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of nuclear plants. We owned Point Beach through September 2007 and placed approximately $215.2 million into this fund. Effective January 31, 1998, the United States Department of Energy (DOE) failed to meet its contractual obligation to begin removing used fuel from Point Beach. We filed a complaint in November 2000 against the DOE in the Court of Federal Claims for failure to begin performance. In December 2009, the Court ruled in our favor, granting us more than $50 million in damages. In February 2010, the DOE filed an appeal. We anticipate that any recoveries will be included in future rate cases.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information concerning market risk exposures at Wisconsin Electric Power Company, 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 2009 Annual Report on Form 10-K.

ITEM 4T. 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.

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 2009 Annual Report on Form 10-K.

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 statements.

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 -- Rates and Regulatory Matters in Part I of this report for information concerning rate matters in the jurisdictions where we do business.

OTHER MATTERS

See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Part I of this report for information on additional legal proceedings.

ITEM 1A. RISK FACTORS

See Item 1A. Risk Factors in our 2009 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

ITEM 5. OTHER INFORMATION

Effective October 26, 2010, Thomas J. Fischer has resigned from the Board of Directors of Wisconsin Electric. Mr. Fischer will remain a director of Wisconsin Energy.

Mr. Fischer has resigned from Wisconsin Electric's Board in order to seek authorizations that may be required from the FERC in connection with potential interlocking directorships. Mr. Fischer presently serves on the Board of Directors of Actuant Corporation, which in the past has sold to Wisconsin Electric indirectly through subsidiaries and third party distributors a small amount of equipment that might be classified by the FERC as electrical equipment. During 2009, sales by Actuant to Wisconsin Electric totaled $15,152, representing approximately 0.0012% of Actuant's net sales.

In addition, Mr. Fischer also sits on the Board of Directors of Regal - Beloit Corporation, which, among other things, manufactures equipment that might be classified by the FERC as electrical equipment. During 2009, Wisconsin Electric purchased $1,777 of equipment produced by Regal - Beloit.

Mr. Fischer intends to file an application with the FERC seeking authorization to serve on Wisconsin Electric's Board, in light of his service on the Boards of Actuant Corporation and Regal - Beloit Corporation. If the FERC grants the application, Mr. Fischer intends to seek reappointment to the Wisconsin Electric Board.

ITEM 6. EXHIBITS

Exhibit No.

10	Material Contracts

10.1	Wisconsin Energy Corporation Death Benefit Only Plan, amended and restated as of July 22, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/10 Form 10-Q.)

12	Statements re Computation of Ratios

12.1	Statement of Computation of Ratio of Earnings to Fixed Charges

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.

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 ELECTRIC POWER COMPANY
	(Registrant)

	/s/STEPHEN P. DICKSON
Date: October 27, 2010	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer