Wisconsin Electric Power Company PFD 3.60% 10Q 2008 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

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

For the Quarterly Period EndedMarch 31, 2008

Commission	Registrant; State of Incorporation		IRS Employer
File Number	Address; and Telephone Number		Identification No.



001-01245	WISCONSIN ELECTRIC POWER COMPANY		39-0476280
		(A Wisconsin Corporation)
		231 West Michigan Street
		P.O. Box 2046
		Milwaukee, WI 53201
		(414) 221-2345

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer [ ] Accelerated filer [ ]

Non-accelerated filer [X] (Do not Smaller reporting company [ ]
check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (March 31, 2008):

Common Stock, $10 Par Value,

33,289,327 shares outstanding.

All of the common stock of Wisconsin Electric Power Company is owned by Wisconsin Energy Corporation.

		WISCONSIN ELECTRIC POWER COMPANY


		FORM 10-Q REPORT FOR THE QUARTER ENDED MARCH 31, 2008



		TABLE OF CONTENTS
Item			Page

	Introduction .......................................................................................................................		8

	Part I -- Financial Information

1.	Financial Statements

	Consolidated Condensed Income Statements ...................................................................		9

	Consolidated Condensed Balance Sheets .........................................................................		10

	Consolidated Condensed Statements of Cash Flows ........................................................		11

	Notes to Consolidated Condensed Financial Statements ..................................................		12

2.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations .................................................................		21

3.	Quantitative and Qualitative Disclosures About Market Risk ..............................................		33

4T.	Controls and Procedures ........................................................................................................		33

	Part II -- Other Information

1.	Legal Proceedings ..................................................................................................................		33

1A.	Risk Factors ..........................................................................................................................		34

5.	Other Information.....................................................................................................................		34

6.	Exhibits ...................................................................................................................................		34

	Signatures ...............................................................................................................................		35

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS


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

Wisconsin Electric Subsidiary and Affiliates

Primary Subsidiary and Affiliates
Bostco		Bostco LLC
Edison Sault		Edison Sault Electric Company
We Power		W.E. Power, LLC
Wisconsin Gas		Wisconsin Gas LLC
Wisconsin Energy		Wisconsin Energy Corporation


Significant Assets
OC 1		Oak Creek expansion Unit 1
OC 2		Oak Creek expansion Unit 2
PWGS		Port Washington Generating Station
PWGS 1		Port Washington Generating Station Unit 1
PWGS 2		Port Washington Generating Station Unit 2


Federal and State Regulatory Agencies
DOE		United States Department of Energy
FERC		Federal Energy Regulatory Commission
IRS		Internal Revenue Service
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources


Environmental Terms
BART		Best Available Retrofit Technology
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CAVR		Clean Air Visibility Rule
EPA		Environmental Protection Agency
NAAQS		National Ambient Air Quality Standards
NO_x		Nitrogen Oxide
PM_2.5		Fine Particulate Matter
SIP		State Implementation Plan
SO₂		Sulfur Dioxide
WPDES		Wisconsin Pollution Discharge Elimination System


Other Terms and Abbreviations
ALJ		Wisconsin Administrative Law Judge
Compensation Committee		Compensation Committee of the Board of Directors of Wisconsin Energy
LSEs		Load Serving Entities
MISO		Midwest Independent Transmission System Operator, Inc.

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS


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

MISO Energy Markets		MISO bid-based energy markets
OTC		Over-the-Counter
Point Beach		Point Beach Nuclear Power Plant
PTF		Power the Future
RSG		Revenue Sufficiency Guarantee
Measurements
MW		Megawatt(s) (One MW equals one million Watts)
MWh		Megawatt-hour(s)
Watt		A measure of power production or usage


Accounting Terms
FASB		Financial Accounting Standards Board
FIN		FASB Interpretation
FSP		FASB Staff Position
GAAP		Generally Accepted Accounting Principles
OPEB		Other Post-Retirement Employee Benefits
SFAS		Statement of Financial Accounting Standards


Accounting Pronouncements
FIN 46		Consolidation of Variable Interest Entities
FSP SFAS 157-b		Determination of Impairment for Nonfinancial Assets and Nonfinancial Liabilities
SFAS 71		Accounting for the Effects of Certain Types of Regulation
SFAS 123R		Share-Based Payment (Revised 2004)
SFAS 133		Accounting for Derivative Instruments and Hedging Activities
SFAS 149		Amendment of SFAS 133 on Derivative Instruments and Hedging Activities
SFAS 157		Fair Value Measurements
SFAS 159		The Fair Value Option for Financial Assets and Financial Liabilities
SFAS 161		Disclosures about Derivative Instruments and Hedging Activities

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements contained in this report are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking te rminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects" or similar terms or variations of these terms.

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

Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related or terrorism-related damage; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; environmental incidents; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; or inflation rates.

Increased competition in our electric and gas markets and continued industry consolidation.

Timing, resolution and impact of pending and future rate cases and negotiations, including recovery for new investments as part of Wisconsin Energy's PTF strategy, environmental compliance, transmission service, fuel costs and costs associated with the implementation of the MISO Energy Markets.

Regulatory factors such as changes in rate-setting policies or procedures; changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; and the siting approval process for new generation and transmission facilities and new pipeline construction.

Factors affecting the economic climate in our service territories such as customer growth; customer business conditions, including demand for their products and services; and changes in market demand and demographic patterns.

Factors which impede execution of Wisconsin Energy's PTF strategy, including receipt of necessary state and federal regulatory approvals and permits; timely and successful resolution of legal challenges, including current challenges to the WPDES permit for the Oak Creek expansion; opposition to siting of new generating facilities; the adverse interpretation or enforcement of permit conditions by the permitting agencies; and obtaining the investment capital from outside sources necessary to implement the strategy.

The impact of recent and future federal, state and local legislative and regulatory changes, including electric and gas industry restructuring initiatives; implementation of the Energy Policy Act; changes in allocation of energy assistance, including state public benefits funds; changes in environmental, tax and other laws and regulations to which we are subject; and changes in the application of existing laws and regulations.

The cost and other effects of legal and administrative proceedings, settlements, investigations, claims and changes in those matters.

Factors affecting the availability or cost of capital such as changes in interest rates and other general capital market conditions; our capitalization structure; market perceptions of the utility industry, us or our subsidiary; or our credit ratings.

The investment performance of our pension and other post-retirement benefit plans.

The effect of accounting pronouncements issued periodically by standard setting bodies.

Unanticipated technological developments that result in competitive disadvantages and create the potential for impairment of existing assets.

Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters.

The cyclical nature of property values that could affect our real estate investments.

Other business or investment considerations that may be disclosed from time to time in our SEC filings or in other publicly disseminated written documents, including the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2007.

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

INTRODUCTION

Wisconsin Electric Power Company, a wholly-owned subsidiary of Wisconsin Energy, was incorporated in the state of Wisconsin in 1896. We maintain our principal executive offices in Milwaukee, Wisconsin. Unless qualified by their context when used in this document, the terms the Company, our, us or we refer to Wisconsin Electric and its subsidiary.

We conduct our operations primarily in three operating segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,112,000 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 458,000 gas customers in Wisconsin and approximately 470 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our business segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 9 -- Segment Information in the Notes to Consolidated Condensed Financial Statements in this report.

Wisconsin Energy is also the parent company of Wisconsin Gas, a natural gas distribution utility, which serves customers throughout Wisconsin; Edison Sault, an electric utility which serves customers in the Upper Peninsula of Michigan; and We Power, an unregulated company that was formed in 2001 to design, construct, own and lease to us the new generating capacity included in Wisconsin Energy's PTF strategy, which is described further in this report and in our 2007 Annual Report on Form 10-K. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies".

Other: Bostco is our non-utility subsidiary that develops and invests in real estate. As of March 31, 2008, Bostco had $38.0 million of assets.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC. We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with GAAP pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2007 Annual Report on Form 10-K, including the financial statements and notes therein.

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

	WISCONSIN ELECTRIC POWER COMPANY
	CONSOLIDATED CONDENSED INCOME STATEMENTS
	(Unaudited)

				Three Months Ended March 31

				2008	2007

				(Millions of Dollars)

	Operating Revenues			$ 985.9	$ 915.5

	Operating Expenses
		Fuel and purchased power		338.3	228.6
		Cost of gas sold		237.1	199.9
		Other operation and maintenance		342.4	274.4
		Depreciation, decommissioning
			and amortization	61.8	69.9
		Property and revenue taxes		24.2	23.1

	Total Operating Expenses			1,003.8	795.9

	Amortization of Gain			159.0	-


	Operating Income			141.1	119.6

	Equity in Earnings of Transmission Affiliate			10.1	9.4
	Other Income, net			8.7	10.1
	Interest Expense, net			22.8	23.7


	Income Before Income Taxes			137.1	115.4

	Income Taxes			53.2	45.2


	Net Income			83.9	70.2

	Preferred Stock Dividend Requirement			0.3	0.3


	Earnings Available for Common Stockholder			$ 83.6	$ 69.9





	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)
			March 31, 2008	December 31, 2007
			(Millions of Dollars)
Assets

Property, Plant and Equipment
	In service		$ 7,084.5	$ 7,052.8
	Accumulated depreciation		(2,616.7)	(2,577.4)

			4,467.8	4,475.4
	Construction work in progress		346.5	302.1
	Leased facilities, net		541.3	547.3

		Net Property, Plant and Equipment	5,355.6	5,324.8

Investments
	Restricted cash		300.4	323.5
	Equity investment in transmission affiliate		212.7	209.9
	Other		0.4	0.4

		Total Investments	513.5	533.8

Current Assets
	Cash and cash equivalents		19.7	22.0
	Restricted cash		342.9	408.1
	Accounts receivable		325.9	264.8
	Accrued revenues		184.7	213.4
	Materials, supplies and inventories		219.3	285.6
	Prepayments		81.7	105.3
	Regulatory assets		69.6	153.0
	Other		82.4	81.1

		Total Current Assets	1,326.2	1,533.3

Deferred Charges and Other Assets
	Regulatory assets		750.1	787.3
	Other		130.8	133.6

		Total Deferred Charges and Other Assets	880.9	920.9

Total Assets			$ 8,076.2	$ 8,312.8




Capitalization and Liabilities

Capitalization
	Common equity		$ 2,688.7	$ 2,656.2
	Preferred stock		30.4	30.4
	Long-term debt		1,191.2	1,338.1
	Capital lease obligations		644.8	646.6

		Total Capitalization	4,555.1	4,671.3

Current Liabilities
	Long-term debt and capital lease obligations due currently		6.2	5.7
	Short-term debt		427.8	354.3
	Accounts payable		318.6	371.0
	Accrued taxes		124.2	60.4
	Regulatory liabilities		469.7	560.8
	Other		132.7	126.0

		Total Current Liabilities	1,479.2	1,478.2

Deferred Credits and Other Liabilities
	Regulatory liabilities		954.8	1,011.0
	Deferred income taxes - long-term		454.3	468.5
	Pension and other benefit obligations		351.6	395.4
	Other long-term liabilities		281.2	288.4

		Total Deferred Credits and Other Liabilities	2,041.9	2,163.3

Total Capitalization and Liabilities			$ 8,076.2	$ 8,312.8





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)

				Three Months Ended March 31

				2008	2007

				(Millions of Dollars)
Operating Activities
	Net income			$ 83.9	$ 70.2
	Reconciliation to cash
		Depreciation, decommissioning and amortization		66.5	72.3
		Equity in earnings of transmission affiliate		(10.1)	(9.4)
		Distributions from transmission affiliate		7.3	6.1
		Deferred income taxes and investment tax credits, net		(9.8)	(22.1)
		Change in -	Accounts receivable and accrued revenues	(32.4)	0.6
			Inventories	66.3	79.1
			Other current assets	21.8	18.4
			Accounts payable	13.2	(38.2)
			Accrued income taxes, net	62.8	39.1
			Deferred costs, net	44.6	(27.9)
			Pension plan contribution	(47.7)	-
			Other current liabilities	7.7	10.3
		Other		(78.5)	46.5

Cash Provided by Operating Activities				195.6	245.0

Investing Activities
	Capital expenditures			(158.4)	(106.5)
	Proceeds from asset sales, net			3.8	0.1
	Change in restricted cash			88.3	-
	Proceeds from investments within nuclear decommissioning trust			-	96.1
	Purchases of investments within nuclear decommissioning trust			-	(96.1)
	Other			(3.8)	(10.3)

Cash Used in Investing Activities				(70.1)	(116.7)

Financing Activities
	Dividends paid on common stock			(54.3)	(44.9)
	Dividends paid on preferred stock			(0.3)	(0.3)
	Retirement and repurchase of long-term debt			(147.0)	(6.3)
	Change in short-term debt			73.5	(89.5)
	Other			0.3	3.9

Cash Used in Financing Activities				(127.8)	(137.1)


Change in Cash and Cash Equivalents				(2.3)	(8.8)

Cash and Cash Equivalents at Beginning of Period				22.0	18.2


Cash and Cash Equivalents at End of Period				$ 19.7	$ 9.4




Supplemental Information - Cash Paid For
	Interest (net of amount capitalized)			$ 4.3	$ 4.7
	Income taxes (net of refunds)			$ -	$ 14.1


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 2007 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 March 31, 2008 are not necessarily indicative of the results which may be expected for the entire fiscal year 2008 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Measurements: In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value to measure assets and liabilities, defines fair value, provides a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We partially adopted the provisions of SFAS 157 effective January 1, 2008. In accordance with FSP SFAS 157-b, we have not applied the provisions of Statement 157 to pension assets, goodwill or asset retirement obligations. The partial adoption of SFAS 157 did not have a significant financial impact on our consolidated financial statements. See Note 5 -- Fair Value Measurements for further information on SFAS 157.

Fair Value Option: In February 2007, the FASB issued SFAS 159. SFAS 159 permits an entity to measure certain financial assets and financial liabilities at fair value and also establishes presentation and disclosure requirements. SFAS 159 is effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007. We adopted the provisions of SFAS 159 effective January 1, 2008. We did not elect to record any financial assets or liabilities at fair value under SFAS 159.

Disclosures about Derivative Instruments and Hedging Activities: In March 2008, the FASB issued SFAS 161. SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for fiscal years beginning after November 15, 2008. We are currently evaluating the provisions of SFAS 161, and we expect to adopt it on January 1, 2009.

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 N -- Common Equity in our 2007 Annual Report on Form 10-K. Effective January 1, 2006, Wisconsin Energy adopted SFAS 123R using the modified prospective method. We utilize the straight-line attribution method for recognizing share-based compensation expense under SFAS 123R. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award, and is recognized as expense over the requisite service period. There were no modifications to outstanding 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 and directors for the three months ended March 31:

	2008	2007

	(Millions of Dollars)

Stock options	$2.8	$4.0
Performance units	1.1	(0.1)
Restricted stock	0.1	0.1

Share-based compensation expense	$4.0	$4.0




Related tax benefit	$1.6	$1.6

Stock Option Activity: During the first three months of 2008, the Compensation Committee granted 1,266,645 Wisconsin Energy stock options to our employees that had an estimated fair value of $9.93 per share. During the first three months of 2007, the Compensation Committee granted 1,252,690 Wisconsin Energy stock options to our employees that had an estimated fair value of $8.72 per share. The following assumptions were used to value the Wisconsin Energy options using a binomial option pricing model:

	2008	2007


Risk free interest rate	2.9% - 3.9%	4.7% - 5.1%
Dividend yield	2.1%	2.2%
Expected volatility	20.0%	13.0% - 20.0%
Expected forfeiture rate	2.0%	2.0%
Expected life (years)	6.7	6.0

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 through the three months ended March 31, 2008:

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


Outstanding as of January 1, 2008	6,512,147	$35.31
Granted	1,266,645	$48.04
Exercised	(69,868)	$29.12
Forfeited	-	-

Outstanding as of March 31, 2008	7,708,924	$37.46	7.0	$60.2





Exercisable as of March 31, 2008	4,351,317	$31.38	5.6	$55.6

The intrinsic value of Wisconsin Energy options exercised by our employees was $1.0 million and $15.2 million for the three months ended March 31, 2008 and 2007, respectively. Cash received by Wisconsin Energy from exercises of their options by our employees was $1.7 million and $19.7 million for the three months ended March 31, 2008 and 2007, respectively. The related tax benefit for the same periods was approximately $0.3 million and $5.7 million, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees that are outstanding as of March 31, 2008:

	Options Outstanding			Options Exercisable

		Weighted-Average			Weighted-Average

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


$12.79 to $23.05	501,923	$21.76	3.3	501,923	$21.76	3.3
$25.31 to $31.07	1,171,721	$27.19	4.7	1,171,721	$27.19	4.7
$33.44 to $48.04	6,035,280	$40.76	7.8	2,677,673	$35.01	6.5

	7,708,924	$37.46	7.0	4,351,317	$31.38	5.6

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the three months ended March 31, 2008:

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


Non-vested as of January 1, 2008	3,160,586	$8.21
Granted	1,266,645	$9.93
Vested	(1,069,624)	$8.35
Forfeited	-	-

Non-vested as of March 31, 2008	3,357,607	$8.81

As of March 31, 2008, our total compensation costs related to non-vested Wisconsin Energy stock options not yet recognized was approximately $16.9 million, which is expected to be recognized over the next 25 months on a weighted-average basis.

Restricted Shares: The Compensation Committee has also approved Wisconsin Energy restricted stock grants to certain key employees and directors. The following restricted stock activity related to our employees occurred during the three months ended March 31, 2008:

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


Outstanding as of January 1, 2008	92,177
Granted	-	-
Released / Forfeited	(7,810)	$22.73

Outstanding as of March 31, 2008	84,367

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 $0.4 million and $1.3 million for the three months ended March 31, 2008 and 2007, respectively. The related tax benefit was zero for the three months ended March 31, 2008, and $0.6 million for the same period in 2007.

As of March 31, 2008, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $0.9 million, which is expected to be recognized over the next 56 months on a weighted-average basis.

Performance Units: In January 2008 and 2007, the Compensation Committee granted 124,175 and 124,655 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 that will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's stock over a three year period. 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. Wisconsin Energy performance units earned as of December 31, 2007 vested and were distributed during the first quarter of 2008 and had a total intrinsic value of $4.7 million. The tax benefit realized due to the distribution of performance units was approximately $1.6 million. As of March 31, 2008, total compensation cost

related to performance units not yet recognized was approximately $9.1 million, which is expected to be recognized over the next 26 months on a weighted-average basis.

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 N -- Common Equity in our 2007 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 normal dividend payments in the foreseeable future.

Comprehensive Income: Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners. We recorded the following total comprehensive income during the three months ended March 31:

Comprehensive Income	2008	2007

	(Millions of Dollars)

Net Income	$83.9	$70.2
Other Comprehensive Income
Hedging	-	-

Total Other Comprehensive Income	-	-

Total Comprehensive Income	$83.9	$70.2

4 -- LONG-TERM DEBT

We are the obligor under two series of insured tax-exempt bonds in outstanding principal amount of $147 million. The bonds bore interest at an "auction rate". In March 2008, because of substantial market disruptions that occurred in the auction rate bond market, we purchased (in lieu of redemption) these bonds at a purchase price of par plus accrued interest to the date of purchase. As of March 31, 2008, the repurchased bonds were still outstanding, but were reported as a reduction in long-term debt. Subject to market conditions, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

5 -- FAIR VALUE MEASUREMENTS

We adopted SFAS 157 as of January 1, 2008, which among other things, requires enhanced disclosures about assets and liabilities that are measured and reported at fair value. SFAS 157 establishes a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value.

As defined in SFAS 157, 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 established under SFAS 157

gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

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.

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 SFAS 157 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 table summarizes our financial assets and liabilities by level within the fair value hierarchy as of March 31, 2008:

Recurring Fair Value Measures
	Level 1	Level 2	Level 3	Total

	(Millions of Dollars)
Assets:
Derivatives	$16.5	$2.5	$4.5	$23.5

Total	$16.5	$2.5	$4.5	$23.5

Liabilities:
Derivatives	$ -	$8.0	$ -	$8.0

Total	$ -	$8.0	$ -	$8.0

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 marke t-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:

		2008

(Millions of Dollars)
Balance as of January 1		$13.0
Realized and unrealized gains (losses)		-
Settlements		(8.5)
Transfers in and/or out of Level 3		-

Balance as of March 31		$4.5




Change in unrealized gains (losses) relating to instruments still held as of March 31		$ -

Changes in fair value for Level 3 recurring items are recorded on our balance sheet in accordance with SFAS 71. See Note 6 -- Derivative Instruments for further information on the offset to regulatory assets and liabilities.

6 -- DERIVATIVE INSTRUMENTS

We follow SFAS 133, as amended by SFAS 149, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. 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 March 31, 2008, we recognized $8.0 million in regulatory assets and $24.3 million in regulatory liabilities related to derivatives.

7 -- BENEFITS

The components of our net periodic pension and OPEB costs for the three months ended March 31 were as follows:

	Pension Benefits		OPEB

Benefit Plan Cost Components	2008	2007	2008	2007

	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$4.4	$7.2	$2.5	$2.9
Interest cost	14.7	15.2	4.1	3.8
Expected return on plan assets	(15.3)	(15.6)	(2.7)	(2.3)
Amortization of:
Transition obligation	-	-	0.1	0.1
Prior service cost (credit)	0.5	1.3	(3.1)	(3.3)
Actuarial loss	2.3	4.0	1.3	1.4

Net Periodic Benefit Cost	$6.6	$12.1	$2.2	$2.6

8 -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties. As of March 31, 2008, 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.

Postemployment benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability, excluding severance benefits, for such benefits was $10.2 million as of March 31, 2008 and $9.8 million as of December 31, 2007.

9 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable operating segments for the three month periods ended March 31, 2008 and 2007 is shown in the following table:

Reportable Operating Segments

Electric	Gas	Steam	Total

(Millions of Dollars)

Three Months Ended


March 31, 2008
Operating Revenues (a)	$660.4	$310.2	$15.3	$985.9
Operating Income	$92.6	$42.2	$6.3	$141.1

March 31, 2007
Operating Revenues (a)	$634.7	$268.1	$12.7	$915.5
Operating Income	$75.3	$39.7	$4.6	$119.6

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

10 -- 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.

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

RESULTS OF OPERATIONS -- THREE MONTHS ENDED MARCH 31, 2008

EARNINGS

We had net income of $83.9 million for the first quarter of 2008, an increase of $13.7 million, or 19.5%, from the first quarter of 2007. A more detailed analysis of our financial results follows.

In September 2007, we sold Point Beach and commenced purchasing power from the new owner under a power purchase agreement. As a result of the sale and the power purchase agreement, our 2008 earnings reflect higher fuel and purchased power costs as compared to 2007. In addition, our 2008 operating income reflects lower other operation and maintenance costs and lower depreciation, decommissioning and amortization costs as we no longer own Point Beach.

In January 2008, we received a rate order from the PSCW that authorized a 17.2% increase in electric rates to recover increased costs associated with transmission expenses, Wisconsin Energy's PTF program, environmental expenditures, continued investment in renewable and efficiency programs and recovery of previously deferred regulatory assets. The PSCW allowed us to issue bill credits to our customers from the proceeds of the net gain and excess decommissioning funds associated with the sale of Point Beach to mitigate this increase. The PSCW also determined that $85.0 million of Point Beach proceeds should be immediately applied to offset certain regulatory assets. As a result of these bill credits, we estimate that the January 2008 PSCW rate order will result in a net 3.2% increase in electric rates paid by our Wisconsin customers and another net increase of 3.2% in 2009. The bill credits that we issue to our customers and the proceeds immediately applied to regulatory assets are reflected on ou r income statement in the amortization of the gain on the sale of Point Beach. As we issue the bill credits, we transfer the cash from a restricted account to an unrestricted account to match the bill credits issued on an after-tax basis.

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the three months ended March 31 including favorable (better (B)) or unfavorable (worse (W)) variances:

	Electric Revenues			MWh Sales

	2008	B(W)	2007	2008	B(W)	2007

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$242.6	$14.6	$228.0	2,153.4	59.1	2,094.3
Small Commercial/Industrial	205.2	2.3	202.9	2,274.0	32.3	2,241.7
Large Commercial/Industrial	152.5	(4.0)	156.5	2,676.0	52.4	2,623.6
Other - Retail	5.4	0.4	5.0	42.9	0.9	42.0

Total Retail Sales	605.7	13.3	592.4	7,146.3	144.7	7,001.6
Wholesale - Other	39.1	19.5	19.6	728.8	266.6	462.2
Resale - Utilities	5.8	(8.3)	14.1	196.2	(68.9)	265.1
Other Operating Revenues	9.8	1.2	8.6	-	-	-

Total	$660.4	$25.7	$634.7	8,071.3	342.4	7,728.9




Weather -- Degree Days (a)
Heating (3,280 Normal)				3,553	282	3,271

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

Our electric utility operating revenues increased by $25.7 million, or 4.0%, when compared to the first quarter of 2007. We estimate that our first quarter 2008 revenues were $7.8 million higher than the first quarter of 2007 due to pricing increases that we received in the January 2008 PSCW rate order and a wholesale rate increase effective in May 2007. For more information on the pricing increases, see Rates and Regulatory Matters in Factors Affecting Results, Liquidity and Capital Resources below. In addition, our wholesale revenues increased by $19.5 million partially due to Edison Sault, which had been a resale customer, switching to a wholesale customer as of January 1, 2008.

We estimate that colder than normal winter weather positively impacted electric sales by $7.4 million during the first quarter of 2008 as compared to the first quarter of 2007. As measured by heating degree days, the first quarter of 2008 was 8.6% colder than the same period in 2007 and 8.3% colder than normal.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $109.7 million, or 48.0%, when compared to the first quarter of 2007. The largest factor related to this increase was the power purchase agreement we entered into in connection with the sale of Point Beach, which increased costs by approximately $64.1 million. In addition, in connection with the January 2008 PSCW rate order, we recorded a $41.2 million one-time amortization of deferred fuel costs in the first quarter of 2008. The remaining increase was $4.4 million, or 1.9%. Increased costs related to increased sales and the impact of higher gas and purchased power prices were offset by higher MWh output of lower-cost coal units. In addition to the continued impact of the Point Beach power purchase agreement, we expect the impact of higher natural gas and fuel oil prices will increase our overall fuel and purchase power costs for the remainder of 2008.

For further information on the 2008 rate order, see Factors Affecting Results, Liquidity and Capital Resources - Rates and Regulatory Matters below.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first quarter of 2008 with similar information for the first quarter of 2007. 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 revenues increased by $42.1 million, or 15.7%, primarily reflecting pricing increases we received in the January 2008 PSCW rate order, increased cost of gas and colder winter weather.

	Three Months Ended March 31

Gas Utility Operations	2008	B (W)	2007

	(Millions of Dollars)

Gas Operating Revenues	$310.2	$42.1	$268.1
Cost of Gas Sold	237.1	(37.2)	199.9

Gross Margin	$73.1	$4.9	$68.2

The following table compares our gas utility gross margin and therm deliveries by customer class during the three months ended March 31:

	Gross Margin			Therm Deliveries

Gas Utility Operations	2008	B (W)	2007	2008	B (W)	2007

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$48.5	$3.0	$45.5	178.3	12.9	165.4
Commercial/Industrial	18.7	1.6	17.1	104.2	8.3	95.9
Interruptible	0.3	-	0.3	2.7	(0.1)	2.8

Total Retail Gas Sales	67.5	4.6	62.9	285.2	21.1	264.1
Transported Gas	4.9	0.3	4.6	102.2	2.2	100.0
Other	0.7	-	0.7	-	-	-

Total	$73.1	$4.9	$68.2	387.4	23.3	364.1



Weather -- Degree Days (a)
Heating (3,280 Normal)				3,553	282	3,271

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

Our gas margins increased by $4.9 million, or approximately 7.2%, when compared to the first quarter of 2007. We estimate that our first quarter 2008 revenues were $0.6 million higher than the first quarter of 2007 reflecting pricing increases that we received in the January 2008 PSCW rate order. In addition, we estimate that colder than normal winter weather positively impacted gas sales by $2.4 million during the first quarter of 2008 as compared to the first quarter of 2007. As measured by heating degree days, the first quarter of 2008 was 8.6% colder than the same period in 2007 and 8.3% colder than normal.

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $68.0 million, or approximately 24.8%, when compared to the first quarter of 2007. As discussed above, we received pricing increases in January 2008 to cover the increased costs. In connection with the January 2008 PSCW rate order, we recorded a $43.8 million one-time amortization of deferred bad debt costs in the first quarter of 2008. In addition, the January 2008 PSCW rate order allowed for increased transmission costs, increased PTF lease costs and other deferred costs totaling approximately $53.1 million. These increases were partially offset by an estimated $37.9 million reduction in nuclear operation and maintenance expense related to the sale of Point Beach as we no longer own the plant.

Depreciation, Decommissioning and Amortization Expense

Our depreciation, decommissioning and amortization expense decreased by $8.1 million, or approximately 11.6%, when compared to the first quarter of 2007. This decrease is primarily the result of the sale of Point Beach. This decrease was partially offset by normal plant additions.

Amortization of Gain

In connection with the September 2007 sale of Point Beach, we reached agreements with our respective regulators to allow for the net gain on the sale of approximately $902.2 million to be used for the benefit of our customers, primarily 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. During the first quarter of 2008, we issued approximately $74.0 million of bill credits to our customers. In addition, pursuant to the January 2008 PSCW rate order, we recorded an $85.0 million one-time amortization of a portion of the gain to reflect the recovery of the amortization of $85.0 million of regulatory assets ($41.2 million related to deferred fuel costs and $43.8 million related to deferred bad debt costs).

Other Income, Net

Other income, net decreased by $1.4 million, or approximately 13.9%, when compared to the first quarter of 2007. This decline primarily relates to lower carrying charges on regulatory assets. In 2007, we accrued carrying charges on regulatory assets. In connection with the January 2008 PSCW rate order, we stopped accruing carrying charges on those regulatory assets as we are now allowed a current return on them.

Interest Expense, Net

	Three Months Ended March 31

Interest Expense, Net	2008	2007

	(Millions of Dollars)

Gross Interest Costs	$23.9	$24.0
Less: Capitalized Interest	1.1	0.3

Interest Expense, Net	$22.8	$23.7

Our gross interest costs decreased by $0.1 million, and our capitalized interest increased by $0.8 million due to higher levels of construction in progress. As a result, our net interest expense declined by $0.9 million, or 3.8%, as compared to the first quarter of 2007.

Income Taxes

For the first quarter of 2008, our effective tax rate was 38.8% compared to 39.2% for the first quarter of 2007.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following summarizes our cash flows during the three months ended March 31:

Wisconsin Electric		2008		2007

		(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$195.6		$245.0
Investing Activities	($70.1)		($116.7)
Financing Activities	($127.8)		($137.1)

Operating Activities

Cash provided by operating activities was $195.6 million during the three months ended March 31, 2008, which was $49.4 million lower than the same period in 2007. During the first quarter of 2008, we experienced an increase in net income reflecting favorable weather; however, there were two significant items that reduced operating cash flows as compared to 2007. In the first quarter of 2008, we contributed $47.7 million to our pension plan. There were no comparable contributions to the plan in the first quarter of 2007. In addition, we experienced an increase in working capital requirements in 2008 that reduced operating cash flows. The increase in working capital was primarily related to an increase in accounts receivable and unbilled revenues caused by higher natural gas prices and colder weather.

Investing Activities

Cash used in investing activities was $70.1 million during the three months ended March 31, 2008, which was $46.6 million lower than the same period in 2007. This decline reflects positive cash flows from the release of restricted cash, partially offset by increased capital expenditures.

During the first quarter of 2008, we saw an increase in cash flows from investing activities as we realized $88.3 million of restricted cash. As background, in September 2007, we sold Point Beach and placed approximately $924 million of cash in restricted accounts to be used for the payment of taxes and for the benefit of our customers. We release the restricted cash on an after-tax basis as we issue bill credits to our customers, which is reflected as an amortization of the gain on our income statement.

During the first quarter of 2008, our capital expenditures increased by $51.9 million primarily due to payments related to our wind generation project.

Financing Activities

Cash used in financing activities was $127.8 million during the three months ended March 31, 2008, which was $9.3 million lower than the same period in 2007. During the first quarter of 2008, we paid approximately $54.3 million in cash dividends and reduced our debt levels by a net amount of approximately $73.5 million.

CAPITAL RESOURCES AND REQUIREMENTS

Capital Resources

We anticipate meeting our capital requirements during the remaining nine months of 2008 primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors. Beyond 2008, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by short-term borrowings and the issuance of debt securities.

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

We have credit agreements that provide liquidity support for our obligations with respect to commercial paper and for general corporate purposes.

As of March 31, 2008, we had approximately $595.1 million of available, undrawn lines under our bank back-up credit facilities. Of that amount, approximately $427.8 million was providing liquidity support for an equivalent amount of short-term debt outstanding on that date.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities as of March 31, 2008:

Total Facility	Letters of Credit	Credit Available	Facility Expiration	Facility Term

(Millions of Dollars)

$500.0	$4.9	$495.1	March 2011	5 year
$100.0 (1)	$ -	$100.0	September 2008	6 month

(1)	On March 3, 2008, we entered into an unsecured six month $100 million bank back-up credit facility. This new facility will expire in September 2008.

We are the obligor under two series of insured tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million that were issued in 2004 (the 2004 Bonds). Since the 2004 Bonds were issued, they have borne interest at an "auction rate". Because of substantial disruptions in the auction rate bond market that occurred in early to mid-February 2008, after giving notice on February 15, 2008 of the exercise of our option to purchase all of the 2004 Bonds (in lieu of redemption), in March 2008 we purchased the 2004 Bonds at a purchase price of par plus accrued interest to the date

of purchase. We issued commercial paper to fund the purchase of the 2004 Bonds. We currently hold the 2004 Bonds. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the 2004 Bonds and have them remarketed to third parties.

Capital Requirements

Capital requirements during the remainder of 2008 are expected to be principally for capital expenditures and long-term debt maturities. Our 2008 annual capital expenditure budget is approximately $600 million.

Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support 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 8 -- Guarantees in the Notes to Consolidated Condensed Financial Statements in this report.

We have identified three tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of any of these three variable interest entities as defined by FIN 46. As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and for the other two contracts as operating leases. For additional information, see Note D -- Variable Interest Entities in our 2007 Annual Report on Form 10-K. We have included our contractual obligations under all three of these contracts in our evaluation of Contractual Obligations/Commercial Commitments discussed below.

Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments are approximately $18.4 billion as of March 31, 2008 compared with $18.8 billion as of December 31, 2007. Our total contractual obligations and other commercial commitments as of March 31, 2008 decreased compared with December 31, 2007 primarily due to periodic payments related to these types of obligations which were greater than new commitments made in the ordinary course of business during the quarter.

FACTORS AFFECTING RESULTS, LIQUDITY AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity and capital resources. The following discussion should be read together with the information under the heading "Factors Affecting Results, Liquidity and Capital Resources" in Item 7 of our 2007 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 PWGS and the Oak Creek expansion, which are being constructed by We Power. We will lease the new units from We Power under long-term leases, and we expect to recover the lease payments in our electric rates. See Factors Affecting Results, Liquidity and Capital

Resources -- Power the Future in Item 7 of our 2007 Annual Report on Form 10-K for additional information on PTF.

Port Washington: Construction of PWGS 2 is essentially complete. Final testing of the unit is in progress. The unit is expected to begin commercial operation during the second quarter of 2008.

Oak Creek Expansion: Construction commenced in June 2005. Adverse weather during the 2007-2008 winter season presented difficulties for the construction contractor; however, the contractor continues to forecast that the units will be completed on schedule. At this time we cannot predict what impact there will be on the project.

A contested case hearing for the WPDES permit was held in March 2006. The ALJ upheld the issuance of the permit in a decision issued in July 2006. In August 2006, the opponents filed in Dane County Circuit Court for judicial review of the ALJ's decision upholding the issuance of the permit. In March 2007, the Dane County Circuit Court affirmed in part the decision by the ALJ to uphold the WDNR's issuance of the permit. The Court also remanded certain aspects of the ALJ's decision for further consideration based on the January 2007 decision by the Federal Court of Appeals for the Second Circuit concerning the federal rule on cooling water intake systems for existing facilities (the Phase II rule) (Riverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) (2d Cir. 2007)). The Second Circuit found certain portions of the rule impermissible and remanded several parts of the rule to the EPA for further consideration or potential rulemaking. In March 2007, the EPA announced its intention to suspend the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems. Consistent with its announcement in March, in July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems for existing facilities.

In November 2007, the ALJ determined that the two additional coal-fired units, OC 1 and OC 2, are new facilities under Section 316(b) of the Clean Water Act. The ALJ did not vacate the WPDES permit or any other permit necessary to continue construction of the two units, pointing out that, based upon the present record, the water intake system currently under construction as part of the Oak Creek expansion may be permittable under the standards that apply to new facilities.

The ALJ remanded the WPDES permit to the WDNR and directed the WDNR to reissue or modify the permit to reflect "best technology available" to comply with the standards applicable to new facilities under Wisconsin state law. As part of the decision, the ALJ restated his prior opinion that the water intake system currently under construction may not be operated until the Wisconsin Division of Hearings and Appeals hears any challenge to a reissued or modified permit.

We believe that there are alternatives under the EPA rule for new facilities that would permit the use of the once-through cooling system under construction rather than the use of cooling towers. We have requested that the WDNR issue a modified permit that authorizes the use of the once-through cooling system under the Phase I rule and have submitted information in support of that request. We anticipate that the WDNR will issue a draft modified permit in the second quarter of 2008. At this time, we cannot predict what the WDNR's decision will be. A re-issued or modified permit will be subject to a public comment period and can be challenged in a hearing before the Wisconsin Division of Hearings and Appeals or through judicial review. While the process for modifying the WPDES permit proceeds, We Power is continuing construction of OC 1 and OC 2 on the current schedule.

In addition, we filed in Milwaukee County Circuit Court a petition for judicial review of the ALJ's decision. We took this action, even though we did not believe that the ALJ's decision was a "final order" that is reviewable, to ensure that we did not lose our right to appeal. The City of Oak Creek and the WDNR also filed petitions for judicial review, and the petitions were consolidated into a single case. At

the time that we filed our petition for review, we also filed a motion requesting a determination from the court that the ALJ order was not final and, therefore, not subject to judicial review at this time. On February 11, 2008, the Court granted our motion dismissing the three petitions for review on the grounds that the ALJ's decision was not a final order and further ruled that all issues decided by the ALJ may be judicially reviewed when there is a final agency decision.

RATES AND REGULATORY MATTERS

2008 Pricing: During 2007, we initiated rate proceedings. We asked the PSCW to approve a comprehensive plan which would result in price increases of $648.6 million for our electric customers in Wisconsin. This price increase would be reduced by expected bill credits resulting from the sale of Point Beach. The initial rate filing estimated bill credits of $371.0 million in 2008 and $187.5 million in 2009, resulting in net pricing increases of 7.5% in 2008 and 7.5% in 2009. In addition, we requested a 1.8% price increase in 2008 for our gas customers and an approximately 16.0% price increase in 2008 for all steam customers in Milwaukee.

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

On January 17, 2008, the PSCW approved pricing increases for us as follows:

$389.1 million (17.2%) in electric rates - the pricing increase will be offset by $315.9 million in bill credits in 2008 and $240.7 million in bill credits in 2009, resulting in a net increase of $73.2 million (3.2%) and $75.2 million (3.2%), respectively;
$4.0 million (0.6%) for natural gas service; and
$3.6 million (11.2%) for steam service.

In addition, the PSCW lowered our return on equity from 11.2% to 10.75%. The PSCW also determined that $85.0 million of the Point Beach proceeds should be immediately applied to offset certain regulatory assets.

We expect to provide a total of approximately $669.7 million of bill credits to our Wisconsin customers over the three year period ending 2010.

Michigan Price Increase Request: On January 31, 2008, we filed a rate increase request with the MPSC. This overall request represents an increase in electric rates of 14.7%, or $22.0 million, to support the growing demand for electricity, continued investment in renewable programs, compliance with environmental regulations, addition of distribution infrastructure and increased operational expenses. This filing also includes a request for immediate rate relief of 5.6%, or approximately $8.4 million. We expect an order from the MPSC during the fourth quarter of 2008.

2008 Fuel Recovery Request: On March 13, 2008, we filed a rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The increase in fuel costs is being driven primarily by increases in the price of natural gas and the higher cost of transporting coal by rail. On April 11, 2008, the PSCW approved an annual increase of $76.9 million (3.3%) in Wisconsin retail electric rates on an interim basis. The increased rates were effective April 15, 2008. The revenues that we collect are subject to refund with interest at a rate of 10.75%, pending PSCW review and final approval.

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 of our 2007 Annual Report on Form 10-K for additional information regarding our rates and other regulatory matters.

ELECTRIC TRANSMISSION AND ENERGY MARKETS

MISO: In MISO, base transmission costs are currently being paid by LSEs located in the service territories of each MISO transmission owner. In February 2008, FERC issued several orders confirming that the current transmission cost allocation methodology is just and reasonable and should continue in the future. These orders are subject to rehearings or appeals.

In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of RSG charges. FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. In October 2006 and March 2007, we received additional rulings from FERC on these issues. FERC's rulings have been challenged by MISO and numerous other market participants. MISO commenced with the resettlement of the market in accordance with the orders in July 2007. The resettlement was completed in January 2008 and resulted in a net cost increase of $7.5 million to us. Several entities filed formal complaints with FERC on the assessment of these charges. We filed in support of these complaints.

In November 2007, FERC issued another RSG order related to the rehearing requests previously filed. This order provided a clarification that was contrary to how MISO implemented the last resettlement. Once again, we filed for rehearing and/or clarification with FERC, along with several other parties.

In addition, FERC ruled on the formal complaints filed by other entities in August 2007. FERC ruled that the current RSG cost allocation methodology may be unjust and unreasonable and established a refund effective date of August 10, 2007. MISO was ordered to file a new cost allocation methodology by March 2008. MISO filed new tariff language which indicated the new cost allocation methodology cannot be applied retroactively. We extended our previous rehearing/clarification request to include the timeframe from the established refund date through March 2008. At this time, we are unable to determine the resulting financial impact, if any, associated with this proceeding.

MISO is in the process of developing a market for two ancillary services, regulation reserves and contingency reserves. In February 2007, MISO filed tariff revisions to include ancillary services. The MISO ancillary services market is expected to begin in September 2008. We currently self-provide both regulation reserves and contingency reserves. In the MISO ancillary services market, we expect that we will buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market is expected to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market is also expected to enable MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Electric Transmission and Energy Markets in Item 7 of our 2007 Annual Report on Form 10-K for additional information regarding MISO.

ENVIRONMENTAL MATTERS

National Ambient Air Quality Standards: In 2000 and 2001, Michigan and Wisconsin finalized state rules implementing phased emission reductions required to meet the NAAQS for 1-hour ozone.In 2004, the EPA began implementing NAAQS for 8-hour ozone and PM_2.5. In December 2006, the EPA further revised the PM_2.5 standard, and in March 2008, the EPA announced its decision to further lower the 8-hour ozone standard.

8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in southeastern Wisconsin as nonattainment areas for the 8-hour ozone NAAQS. States were required to develop and submit SIPs to the EPA by June 2007 to demonstrate how they intend to comply with the 8-hour ozone NAAQS. Instead of submitting a SIP, Wisconsin submitted a request to redesignate all counties in southeastern Wisconsin to be in attainment with the standard. In addition to the request for redesignation, Wisconsin also adopted a rule that applies to emissions from our power plants in the affected areas of Wisconsin. The required reductions will be accomplished through implementation of the CAIR. (See below for further information regarding CAIR.) We believe compliance with the NO_x emission reduction requirements under the Consent Decree will substantially mitigate costs to comply with the EPA's 8-hour ozone NAAQS. In March 2008, the EPA issued a determination that the state o f Wisconsin had failed to submit a SIP. We do not anticipate any further requirements to reduce emissions as a result of this finding, but we are unable to predict that outcome until Wisconsin responds to this finding and the EPA subsequently takes a final approval action. In March 2008, the EPA announced its decision to further lower the 8-hour standard. Although additional counties may be designated as non-attainment areas under the revised standard, until those designations become final and until any potential additional rules are adopted, we are unable to predict the impact on the operation of our existing coal-fired generation facilities.

Clean Air Interstate Rule: The EPA issued the final CAIR in March 2005 to facilitate the states in meeting the 8-hour ozone and PM_2.5 standards by addressing the regional transport of SO₂ and NO_x. CAIR requires NO_x and SO₂ emission reductions in two phases from electric generating units located in a 28-state region within the eastern United States. Wisconsin and Michigan are affected states under CAIR. The phase 1 compliance deadline is January 1, 2009 for NO_x and January 1, 2010 for SO₂, and the phase 2 compliance deadline is January 1, 2015 for both NO_x and SO₂. Overall, CAIR is expected to result in a 70% reduction in SO₂ emissions and a 65% reduction in NO_x emissions from 2002 emission levels. The states were required to develop and submit implementation plans by no later than March 2007. A final CAIR rule has b een adopted in Wisconsin and Michigan. We believe that compliance with the NO_x and SO₂ emission reductions requirements under the Consent Decree will substantially mitigate costs to comply with the CAIR rule. The CAIR rule is currently being litigated.

Clean Air Mercury Rule: The EPA issued the final CAMR in March 2005, following the agency's 2000 regulatory determination that utility mercury emissions should be regulated. CAMR would limit mercury emissions from newand existing coal-fired power plants, and cap utility mercury emissions in two phases, applicable in 2010 and 2018. The caps would limit emissions at approximately 20% and ultimately 70% below today's utility mercury levels.

The federal rule was challenged by a number of states, including Wisconsin and Michigan. In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAMR and sent the rule back to EPA for re-consideration. At this time, we cannot predict the timing or impact on our operations of a future federal rule.

In October 2004, the WDNR issued mercury emission control rules that affect electric utilities in Wisconsin. The Wisconsin rules explicitly recognize an underlying state statutory restriction that state

regulations cannot be more stringent than those included in any federal program and require that the WDNR must adopt state rule changes within 18 months of publication of any federal rules. In March 2007, the WDNR proposed changes to this rule to include an implementation plan for CAMR, along with a proposal for more stringent state-only rules. WDNR did not take any final action on the March 2007 rule proposal. The 2004 state rule will continue to apply to our Wisconsin facilities, unless and until it is revised in the future. This rule requires mercury emission reductions from existing coal-fueled units in three phases, beginning with an emission cap in 2008, and followed by a 40% reduction requirement by 2010 and a 75% reduction requirement by 2015.

In March 2008, the WDNR once again proposed changes to the existing state-only mercury rule. The new proposal would require 90% emission reductions from utilities by 2015, or, under a multi-emission option, 70% reductions by 2015, 80% by 2018 and 90% by 2021, provided utilities meet stringent NO_x and SO₂ emission reduction requirements by 2015. The proposed rule would eliminate the 2008-09 emission cap, but retain the 40% emission reduction requirement for the period 2010-2014. Our plan is to maximize mercury reductions from our initial emission control investments. Enhanced mercury reductions from refinements to SO₂ and NO_x controls are expected to be developed over the next several years. Because control technology is under development, it is difficult to estimate what the cost would be to comply with the Wisconsin requirements. We believe the range of possible expenditures could be approximately $50 million to $200 million.

As of January 2008, the MDEQ has also proposed a rule to both implement CAMR and impose state-only requirements for achieving 90% emission reductions in 2015. The MDEQ has withdrawn the draft rule to remove the requirements related to the now vacated CAMR, but intends to proceed with the remainder of the state-only rule as proposed. As part of a new technology demonstration which we undertook in partnership with the DOE, technology for the control of mercury has been installed at Presque Isle Power Plant. We plan to continue the operation of that equipment beyond the test period. We anticipate that this equipment will be sufficient to comply with reductions that would be required under the state-only rule.

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

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2007 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information concerning market risk exposures at Wisconsin 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 2007 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 2007 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.

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

ITEM 1A. RISK FACTORS

See Item 1A. Risk Factors in our 2007 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

ITEM 5. OTHER INFORMATION

Director John F. Ahearne did not stand for re-election at the 2008 Annual Meeting of Stockholders of Wisconsin Energy held on May 1, 2008, at which time his term expired. Director Ahearne has served on the Boards of Directors of Wisconsin Energy and Wisconsin Electric since 1994 and on the Board of Directors of Wisconsin Gas since 2000. In consideration of his exemplary service to these Boards of Directors, on May 1, 2008, the Compensation Committee of the Board of Directors of Wisconsin Energy approved the acceleration of vesting of all unvested restricted stock awarded to Director Ahearne consisting of 4,914 shares of restricted stock.

ITEM 6. EXHIBITS

Exhibit No.

10	Material Contracts

10.1	Point Beach Nuclear Plant Power Purchase Agreement between FPL Energy Point Beach, LLC and Wisconsin Electric Power Company, dated as of December 19, 2006. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/08 Form 10-Q (File No. 001-09057).)

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: May 1, 2008	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer

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Wisconsin Electric Power Company PFD 3.60% (WELPP) 10-Q2008 Q1 Quarterly report

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