Wisconsin Electric Power Company PFD 3.60% 10Q 2007 Q3 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 EndedSeptember 30, 2007

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, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X].

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

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

Common Stock, $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 SEPTEMBER 30, 2007



		TABLE OF CONTENTS
Item			Page

	Introduction		7

	Part I -- Financial Information

1.	Financial Statements

	Consolidated Condensed Income Statements		8

	Consolidated Condensed Balance Sheets		9

	Consolidated Condensed Statements of Cash Flows		10

	Notes to Consolidated Condensed Financial Statements		11

2.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations		19

3.	Quantitative and Qualitative Disclosures About Market Risk		35

4.	Controls and Procedures		35

	Part II -- Other Information

1.	Legal Proceedings		36

1A.	Risk Factors		36

6.	Exhibits		37

	Signatures		38

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 Energy		Wisconsin Energy Corporation
Wisconsin Gas		Wisconsin Gas LLC


Significant Assets
OC 1		Oak Creek expansion Unit 1
OC 2		Oak Creek expansion Unit 2
Point Beach		Point Beach Nuclear Plant
PWGS		Port Washington Generating Station
PWGS 2		Port Washington Generating Station Unit 2


Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources


Environmental Terms
BART		Best Available Retrofit Technology
BTA		Best Technology Available
CAIR		Clean Air Interstate Rule
CAVR		Clean Air Visibility Rule
CO₂		Carbon Dioxide
NO_X		Nitrogen Oxide
PM_2.5		Fine Particulate Matter
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
CPCN		Certificate of Public Convenience and Necessity
Fitch		Fitch Ratings
FPL		FPL Group, Inc.
FTRs		Financial Transmission Rights
LMP		Locational Marginal Price
MISO		Midwest Independent Transmission System Operator, Inc.
MISO Midwest Market		MISO bid-based energy market
Moody's		Moody's Investor Services
NEIL		Nuclear Electric Insurance Limited

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.

PJM		PJM Interconnection, L.L.C.
PTF		Power the Future
RSG		Revenue Sufficiency Guarantee
S&P		Standard & Poor's Corporation


Measurements
MW		Megawatt(s) (One MW equals one million watts)
MWh		Megawatt-hour(s)


Accounting Terms
AFUDC		Allowance for Funds Used During Construction
FASB		Financial Accounting Standards Board
FIN		FASB Interpretation
GAAP		Generally Accepted Accounting Principles
OPEB		Other Post-Retirement Employee Benefits
SFAS		Statement of Financial Accounting Standards


Accounting Pronouncements
FIN 46		Consolidation of Variable Interest Entities
FIN 48		Accounting for Uncertainty in Income Taxes
SFAS 109		Accounting for Income Taxes
SFAS 123R		Share-Based Payment (Revised 2004)
SFAS 133		Accounting for Derivative Instruments and Hedging Activities
SFAS 149		Amendment of SFAS 133 on Derivative Instruments and Hedging Activities
SFAS 157		Fair Value Measurements
SFAS 159		The Fair Value Option for Financial Assets and Financial Liabilities

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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, including without limitation the Point Beach Nuclear Plant Power Purchase Agreement; environmental incidents; resolution of used nuclear fuel storage and disposal issues; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; infla tion rates; or demographic and economic factors affecting utility service territories or operating environment.

Regulatory factors such as unanticipated changes in rate-setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; recovery of costs of previous investments made under traditional regulation; recovery of costs associated with adoption of changed accounting standards; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; changes in the United States Nuclear Regulatory Commission's regulations that may affect the operation of Point Beach and our ability to obtain power pursuant to the terms of the Point Beach Nuclear Plant Power Purchase Agreement; changes in the regulations of the EPA as well as the WDNR, the Michigan Department of Natural Resources or the Michigan Department of Environmental Quality, including but not limited to regulations relating to the release of emissions from fossil-fueled power plants such as CO₂, SO₂, NO_x, small particulates or mercury, water quality and lead paint, and regulations relating to the intake and discharge of water; the siting approval process for new generation and transmission facilities; recovery of costs associated with implementation of the MISO Midwest Market; or changes in the regulations from the WDNR related to the siting approval process for new pipeline construction.

The changing electric and gas utility environment as market-based forces replace strict industry regulation and other competitors enter the electric and gas markets resulting in increased wholesale and retail competition.

5

Unanticipated operational and/or financial consequences related to implementation of the MISO Midwest Market that started in April 2005.

Consolidation of the industry as a result of the combination and acquisition of utilities in the Midwest, nationally and globally as a result of the repeal of the Public Utility Holding Company Act of 1935 or otherwise.

Factors which impede execution of Wisconsin Energy's PTF strategy, including receipt of necessary state and federal regulatory approvals, timely and successful resolution of legal challenges, local opposition to siting of new generating facilities, construction risks, including 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.

Changes in social attitudes regarding the utility and power industries.

Customer business conditions including demand for their products or services and supply of labor and material used in creating their products and services.

The cost and other effects of legal and administrative proceedings, settlements, investigations and 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 any of our subsidiaries; or security ratings.

Federal, state or local legislative factors such as changes in tax laws or rates; changes in trade, monetary and fiscal policies, laws and regulations; electric and gas industry restructuring initiatives; changes in the Price-Anderson Act; changes in environmental laws and regulations; or changes in allocation of energy assistance, including state public benefits funds.

Implementation of the Energy Policy Act of 2005 and the effect of state level proceedings and the development of regulations by federal and other agencies, including FERC.

Authoritative GAAP or policy changes from such standard setting bodies as the FASB, the SEC and the Public Company Accounting Oversight Board.

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

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, 2006.

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 report, 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 1,105,900 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 454,500 gas customers in Wisconsin and about 460 steam customers in metro 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 10 -- 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 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 2006 Annual Report on Form 10-K. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies."

Sale of Point Beach: In September 2007, we completed the sale of Point Beach to an affiliate of FPL for approximately $924 million. In addition, the buyer assumed certain liabilities related to the plant, including responsibility to decommission Point Beach. We intend to use the net gain from the sale and certain decommissioning funds that we retained as a result of the sale to benefit customers, as determined by our regulators. See Note 3 -- Sale of Point Beach in the Notes to Consolidated Condensed Financial Statements in this report.

Other: Bostco is our non-utility subsidiary that develops and invests in real estate. As of September 30, 2007, Bostco had $38.5 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 2006 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 September 30		Nine Months Ended September 30

	2007	2006	2007	2006

	(Millions of Dollars)

Operating Revenues	$ 784.7	$ 745.2	$ 2,458.4	$ 2,303.7

Operating Expenses
Fuel and purchased power	253.2	228.7	712.9	580.8
Cost of gas sold	32.5	36.7	299.4	296.6
Other operation and maintenance	263.9	264.0	821.2	796.3
Depreciation, decommissioning
and amortization	71.1	68.1	207.8	202.0
Property and revenue taxes	23.3	21.6	68.8	65.0

Total Operating Expenses	644.0	619.1	2,110.1	1,940.7


Operating Income	140.7	126.1	348.3	363.0

Equity in Earnings of Transmission Affiliate	9.5	8.5	28.2	25.2
Other Income, Net	13.9	13.1	41.5	36.4
Interest Expense	24.2	20.7	71.1	64.5


Income Before Income Taxes	139.9	127.0	346.9	360.1

Income Taxes	54.8	49.0	135.7	137.6


Net Income	85.1	78.0	211.2	222.5

Preferred Stock Dividend Requirement	0.3	0.3	0.9	0.9


Earnings Available for Common Stockholder	$ 84.8	$ 77.7	$ 210.3	$ 221.6





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, 2007	December 31, 2006
	(Millions of Dollars)
Assets

Property, Plant and Equipment
In service	$ 7,017.2	$ 7,570.4
Accumulated depreciation	(2,559.9)	(2,914.0)

	4,457.3	4,656.4
Construction work in progress	104.6	99.7
Leased facilities, net	390.8	404.0
Nuclear fuel, net	-	130.9

Net Property, Plant and Equipment	4,952.7	5,291.0

Investments
Restricted cash	969.1	-
Nuclear decommissioning trust fund	-	881.6
Equity investment in transmission affiliate	207.8	201.2
Other	0.4	0.4

Total Investments	1,177.3	1,083.2

Current Assets
Cash and cash equivalents	495.8	18.2
Accounts receivable	267.3	297.2
Accrued revenues	134.7	189.3
Materials, supplies and inventories	303.3	313.0
Prepayments and other	84.6	110.7

Total Current Assets	1,285.7	928.4

Deferred Charges and Other Assets
Regulatory assets	963.0	859.5
Other	122.8	95.7

Total Deferred Charges and Other Assets	1,085.8	955.2

Total Assets	$ 8,501.5	$ 8,257.8




Capitalization and Liabilities

Capitalization
Common equity	$ 2,664.7	$ 2,528.6
Preferred stock	30.4	30.4
Long-term debt	1,337.8	1,337.1
Capital lease obligations	486.0	534.5

Total Capitalization	4,518.9	4,430.6

Current Liabilities
Long-term debt and capital lease obligations due currently	255.3	280.5
Short-term debt	322.5	304.2
Accounts payable	330.5	287.2
Accrued liabilities	561.2	201.9
Other	56.7	86.8

Total Current Liabilities	1,526.2	1,160.6

Deferred Credits and Other Liabilities
Regulatory liabilities	1,546.8	1,142.3
Deferred income taxes - long-term	167.1	510.1
Asset retirement obligations	49.4	371.1
Other	693.1	643.1

Total Deferred Credits and Other Liabilities	2,456.4	2,666.6

Total Capitalization and Liabilities	$ 8,501.5	$ 8,257.8




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)

	Nine Months Ended September 30

	2007	2006

	(Millions of Dollars)
Operating Activities
Net income	$ 211.2	$ 222.5
Reconciliation to cash
Depreciation, decommissioning and amortization	214.9	209.1
Nuclear fuel expense amortization	23.2	22.1
Equity in earnings of transmission affiliate	(28.2)	(25.2)
Distributions from transmission affiliate	21.6	20.1
Deferred income taxes and investment tax credits, net	(28.2)	(20.7)
Change in - Accounts receivable and accrued revenues	84.5	116.0
Inventories	(14.8)	(2.5)
Other current assets	26.1	3.7
Accounts payable	41.7	(67.6)
Accrued income taxes, net	39.3	16.3
Deferred costs, net	(60.5)	(19.4)
Other current liabilities	(1.6)	52.9
Other	(115.0)	(29.3)

Cash Provided by Operating Activities	414.2	498.0

Investing Activities
Capital expenditures	(276.8)	(276.2)
Proceeds from asset sales, net	935.6	3.2
Proceeds from liquidation of nuclear decommissioning trust	552.4	-
Cash designated as restricted cash	(969.1)	-
Investment in transmission affiliate	-	(12.8)
Nuclear fuel	(23.8)	(20.4)
Nuclear decommissioning funding	(11.7)	(13.2)
Proceeds from investments within nuclear decommissioning trust	1,528.7	430.8
Other activity within nuclear decommissioning trust	(1,528.7)	(430.8)
Other	(4.2)	(3.5)

Cash Provided by (Used in) Investing Activities	202.4	(322.9)

Financing Activities
Dividends paid on common stock	(89.8)	(89.8)
Dividends paid on preferred stock	(0.9)	(0.9)
Issuance of long-term debt	23.4	-
Retirement of long-term debt	(95.4)	(22.3)
Change in short-term debt	18.3	(172.0)
Capital contribution from parent	-	100.0
Other	5.4	1.6

Cash Used in Financing Activities	(139.0)	(183.4)


Change in Cash and Cash Equivalents	477.6	(8.3)

Cash and Cash Equivalents at Beginning of Period	18.2	23.2


Cash and Cash Equivalents at End of Period	$ 495.8	$ 14.9




Supplemental Information - Cash Paid For
Interest (net of amount capitalized)	$ 52.7	$ 45.9
Income taxes (net of refunds)	$ 119.5	$ 150.8


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

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Uncertainty in Income Taxes: In July 2006, the FASB issued FIN 48, an interpretation of SFAS 109. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS 109. As of January 1, 2007, the adoption date for FIN 48, the amount of unrecognized tax benefits was approximately $13.3 million, which included estimated accrued interest and penalties of $0.8 million. We recognize accrued interest and penalties in the provision for income taxes. The impact of adopting FIN 48 was not material. As of the date of adoption, the net amount of the unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $8.4 million. We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months. Our primary tax jurisdic tions include federal and the State of Wisconsin. Currently, the tax years of 2004 through 2006 are subject to federal examination and the tax years of 2002 through 2006 are subject to examination by the State of Wisconsin.

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

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

3 -- SALE OF POINT BEACH

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

In connection with the sale, we also transferred $390 million of decommissioning funds to the buyer. We then liquidated the balance of the decommissioning trust assets and retained approximately $552 million of that cash. This cash was also placed in the restricted cash account. We intend to use the cash in the restricted cash account and the interest earned on the balance, for the benefit of our customers and to pay certain taxes related to the liquidation of the qualified decommissioning trust. Our regulators will decide the manner in which these proceeds will benefit customers in future rate proceedings. For further information on the 2008 Rate Case, see Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources - Rates and Regulatory Matters in this report.

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

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

4 -- ASSET RETIREMENT OBLIGATIONS

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

	Balance at 12/31/06	Liabilities Incurred	LiabilitiesSettled	Accretion	Cash Flow Revisions	Balance at 9/30/07
	(Millions of Dollars)
Asset Retirement Obligations	$371.1	$ -	($338.4)	$14.3	$2.4	$49.4

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

5 -- 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 2006 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.

	Three Months Ended September 30		Nine Months Ended September 30

	2007	2006	2007	2006

	(Millions of Dollars)

Stock options	$2.3	$1.8	$8.5	$5.2
Performance units	0.9	1.5	2.0	3.8
Restricted stock	0.1	0.1	0.3	0.3

Share-based compensation expense	$3.3	$3.4	$10.8	$9.3




Related Tax Benefit	$1.3	$1.3	$4.3	$3.7

Stock Option Activity: During the first nine months of 2007, the Compensation Committee granted 1,252,690 Wisconsin Energy options to our employees that had an estimated fair value of $8.72 per share. During the first nine months of 2006, the Compensation Committee granted 1,175,219 Wisconsin Energy options to our employees that had an estimated fair value of $7.55 per share. The following assumptions were used to value the Wisconsin Energy options using a binomial option pricing model:

	2007	2006


Risk free interest rate	4.7% - 5.1%	4.3% - 4.4%
Dividend yield	2.2%	2.4%
Expected volatility	13.0% - 20.0%	17.0% - 20.0%
Expected forfeiture rate	2.0%	2.0%
Expected life (years)	6.0	6.3

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

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

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


Outstanding as of July 1, 2007	6,646,467	$35.10
Granted	-	-
Exercised	(10,075)	$22.33
Forfeited	-	-

Outstanding as of September 30, 2007	6,636,392	$35.12




Outstanding as of January 1, 2007	6,327,794	$31.43
Granted	1,252,690	$47.76
Exercised	(933,128)	$27.01
Forfeited	(10,964)	$35.66

Outstanding as of September 30, 2007	6,636,392	$35.12	6.9	$69.2




Exercisable as of September 30, 2007	3,467,769	$30.00	5.6	$52.5

The intrinsic value of Wisconsin Energy options exercised by our employees was $0.2 million and $19.8 million for the three and nine months ended September 30, 2007, and $3.3 million and $6.0 million for the same periods in 2006, respectively. Cash received by Wisconsin Energy from exercises of their options by our employees was $24.4 million and $8.3 million for the nine months ended September 30, 2007 and 2006, respectively. The related tax benefit for the same periods was approximately $7.4 million and $2.4 million, respectively.

The following table summarizes information about our employees' non-vested Wisconsin Energy options for the three and nine months ended September 30, 2007:

	Three Months		Nine Months

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


Non-vested - Beginning of Period	3,168,623	$8.21	2,286,578	$7.93
Granted	-	-	1,252,690	$8.72
Vested	-	-	(363,481)	$8.25
Forfeited	-	-	(7,164)	$8.18

Non-vested as of September 30, 2007	3,168,623	$8.21	3,168,623	$8.21

As of September 30, 2007, our total compensation costs related to non-vested Wisconsin Energy stock options not yet recognized was approximately $9.9 million, which is expected to be recognized over the next 21 months on a weighted-average basis.

The following table summarizes information about Wisconsin Energy stock options held by our employees that are outstanding as of September 30, 2007:

	Options Outstanding			Options Exercisable

		Weighted-Average			Weighted-Average

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


$12.79 to $23.05	580,753	$27.76	3.8	580,753	$21.76	3.8
$25.31 to $31.07	1,242,147	$27.20	5.1	1,242,147	$27.20	5.1
$33.44 to $47.76	4,813,492	$38.78	7.7	1,644,869	$35.04	6.6

	6,636,392	$35.12	6.9	3,467,769	$30.00	5.6

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 and nine months ended September 30, 2007:

	Three Months		Nine Months

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


Outstanding - Beginning of Period	99,864		131,945
Granted	-	-	-	-
Released / Forfeited	(5,023)	$28.67	(37,104)	$24.91

Outstanding as of September 30, 2007	94,841		94,841

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 held by our employees and vested was $0.2 million and $1.7 million for the three and nine months ended September 30, 2007, respectively, and zero for the same periods in 2006. The related tax benefit was zero and $0.6 million for the three and nine months ended September 30, 2007, respectively, and zero for the same periods in 2006.

As of September 30, 2007, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $1.3 million, which is expected to be recognized over the next 55 months on a weighted-average basis.

Performance Units: In January 2007 and 2006, the Compensation Committee granted 124,655 and 135,392 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 held by our employees and vesting were approximately $0.6 million, with a related tax benefit of $0.3 million, during the nine months ended September 30, 2007. Wisconsin Energy performance shares earned as of December 31, 2006, vested and were distributed during the first quarter of 2007 and had a total intrinsic value of $6.5 million. The tax benefit realized due to the distribution of performance shares was approximately $1.9 million. As of September 30, 2007, total compensation cost

related to performance units not yet recognized was approximately $6.2 million, which is expected to be recognized over the next 22 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 2006 Annual Report on Form 10-K for additional information on these 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. During the nine months ended September 30, 2007 and September 30, 2006, total comprehensive income was equal to net income.

6 -- LONG-TERM DEBT

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

7 -- DERIVATIVE INSTRUMENTS

We follow SFAS 133, as amended by SFAS 149, effective July 1, 2003, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of September 30, 2007, we recognized $9.0 million in regulatory assets and $1.6 million in regulatory liabilities related to derivatives.

8 -- BENEFITS

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

	Pension Benefits		OPEB

	2007	2006	2007	2006

	(Millions of Dollars)
Three Months Ended September 30
Net Periodic Benefit Cost
Service cost	$6.7	$7.6	$2.7	$2.9
Interest cost	15.2	14.9	3.8	3.5
Expected return on plan assets	(15.4)	(14.9)	(2.3)	(2.1)
Amortization of:
Transition obligation	-	-	0.1	0.1
Prior service cost (credit)	1.5	1.4	(3.3)	(3.3)
Actuarial loss	3.1	5.0	1.4	1.7

Net Periodic Benefit Cost	$11.1	$14.0	$2.4	$2.8




Nine Months Ended September 30
Net Periodic Benefit Cost
Service cost	$20.4	$22.9	$8.2	$8.8
Interest cost	45.9	44.7	11.3	10.6
Expected return on plan assets	(46.2)	(44.9)	(6.9)	(6.5)
Amortization of:
Transition obligation	-	-	0.3	0.3
Prior service cost (credit)	4.3	4.1	(10.0)	(10.0)
Actuarial loss	10.7	15.2	4.3	5.2

Net Periodic Benefit Cost	$35.1	$42.0	$7.2	$8.4

9 -- GUARANTEES

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

Maximum Potential Future Payments	Outstanding at September 30, 2007	Liability Recorded at September 30, 2007

(Millions of Dollars)

$2.8	$0.1	$ -

We guarantee the potential retrospective premiums that could be assessed under our nuclear insurance program (see Note 3 -- Sale of Point Beach in this report).

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 $9.0 million as of September 30, 2007 and December 31, 2006.

10 -- SEGMENT INFORMATION

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

	Reportable Operating Segments

	Electric	Gas		Steam		Total

	(Millions of Dollars)
Three Months Ended


September 30, 2007
Operating Revenues (a)	$724.9	$54.5		$5.3		$784.7
Operating Income (Loss)	$145.8	($3.9	)	($1.2	)	$140.7

September 30, 2006
Operating Revenues (a)	$681.5	$59.0		$4.7		$745.2
Operating Income (Loss)	$131.1	($4.0	)	($1.0	)	$126.1

Nine Months Ended


September 30, 2007
Operating Revenues (a)	$2,014.0	$419.3		$25.1		$2,458.4
Operating Income	$305.6	$38.9		$3.8		$348.3

September 30, 2006
Operating Revenues (a)	$1,878.4	$406.1		$19.2		$2,303.7
Operating Income	$337.4	$25.2		$0.4		$363.0

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

11 -- COMMITMENTS AND CONTINGENCIES

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

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

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

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

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

EARNINGS

We had net income of $85.1 million for the third quarter of 2007, an increase of $7.1 million, or 9.1%, from the third quarter of 2006. The two biggest drivers of the increase were the timing of fuel and purchased power costs and recoveries, and increased electric MWh sales volumes. We estimate milder summer weather during the third quarter of 2007 compared with the same period in 2006 partially offset this increase. In addition, there was an increase in depreciation, decommissioning and amortization costs and interest expense. A more detailed analysis of our financial results follows.

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

Electric Utility Revenues and Sales

The following table compares our electric utility operating revenues and MWh sales by customer class during the third quarter of 2007 with the third quarter of 2006 including favorable (better (B)) or unfavorable (worse (W)) variances.

	Three Months Ended September 30

	Electric Revenues			MWh Sales

	2007	B(W)	2006	2007	B(W)		2006

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$251.6	$8.0	$243.6	2,330.5	24.1		2,306.4
Small Commercial/Industrial	225.2	8.7	216.5	2,480.8	41.7		2,439.1
Large Commercial/Industrial	174.4	6.5	167.9	2,930.3	53.6		2,876.7
Other-Retail	4.6	0.2	4.4	37.7	(0.5	)	38.2

Total Retail Sales	655.8	23.4	632.4	7,779.3	118.9		7,660.4
Wholesale-Other	22.5	3.7	18.8	493.7	35.9		457.8
Resale-Utilities	35.1	15.8	19.3	504.2	221.4		282.8
Other Operating Revenues	11.5	0.5	11.0	-	-		-

Total	$724.9	$43.4	$681.5	8,777.2	376.2		8,401.0




Weather -- Degree Days (a)
Cooling (531 Normal)				567	(10	)	577

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

During the third quarter of 2007, total electric utility operating revenues increased by $43.4 million, or 6.4%, when compared with the third quarter of 2006. The two biggest drivers of the increase were revenues attributable to fuel and purchased power of approximately $14.6 million and increased revenues related to Resale-Utilities of approximately $15.8 million. Our policy for electric fuel revenues is to not recognize revenue for any currently billable amounts if it is probable that we will refund those amounts to customers. In 2006, we experienced lower than expected fuel and purchased power costs, and we established $14.6 million of reserves to reflect amounts that we expected to refund to customers. No such reserves have been established in 2007, as we are experiencing higher fuel and purchased power costs. The increase in Resale-Utilities reflects our ability to sell electricity into the MISO and PJM markets due to increased availability of our base-load plants.

Total electric MWh sales volumes increased by 376.2 thousand MWh, or 4.5%, in the third quarter of 2007 compared with the same period in 2006. The largest increase came from sales to other utilities, as discussed above. Our retail sales increased by 1.6%, as compared to the same period last year. For the quarter, the weather, as measured by cooling degree days, was slightly warmer than normal and slightly cooler than the same period in 2006.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $24.5 million, or 10.7%, when compared to the third quarter of 2006. As noted above, our total electric sales volume increased by approximately 4.5% in the quarter; however, our average fuel and purchased power cost per MWh increased by $1.68 or approximately 6.6%. The higher cost per MWh was due to an 8.3% increase in the cost of coal and coal transportation contracts between periods. In addition, we experienced higher utilization in our gas

generation and purchased energy in the quarter ended September 30, 2007, as compared to the same period in 2006. This generation was primarily related to the increased revenue related to Resale-Utilities.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the third quarter of 2007 with the third quarter of 2006. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas margins decreased by $0.3 million, or 1.3%.

	Three Months Ended September 30

	2007	B (W)		2006

	(Millions of Dollars)

Gas Operating Revenues	$54.5	($4.5	)	$59.0
Cost of Gas Sold	32.5	4.2		36.7

Gross Margin	$22.0	($0.3	)	$22.3

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

	Three Months Ended September 30

	Gross Margin				Therm Deliveries

	2007	B (W)		2006	2007	B (W)		2006

	(Millions of Dollars)				(Millions)
Customer Class
Residential	$14.1	($0.2	)	$14.3	20.6	(1.4	)	22.0
Commercial/Industrial	4.0	-		4.0	13.9	(1.0	)	14.9
Interruptible	0.1	-		0.1	0.9	-		0.9

Total Retail Gas Sales	18.2	(0.2	)	18.4	35.4	(2.4	)	37.8
Transported Gas	3.5	-		3.5	81.9	10.7		71.2
Other	0.3	(0.1	)	0.4	-	-		-

Total	$22.0	($0.3	)	$22.3	117.3	8.3		109.0




Weather -- Degree Days (a)
Heating (132 Normal)					108	(20	)	128

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

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

Other Income, Net

Other income, net increased by $0.8 million, or 6.1%, when compared to the third quarter of 2006. The increase primarily consists of approximately $2.9 million related to gains on the sale of additional land in Northern Wisconsin and the Upper Peninsula of Michigan and capitalized carrying costs. The increases were offset, in part, by a decrease in AFUDC of $3.2 million in connection with the new scrubber we put in service at our Pleasant Prairie Power Plant during the fourth quarter of 2006. This scrubber was

installed as part of our EPA consent decree spending. For further information on the consent decree with the EPA, see Note 11 -- Commitments and Contingencies in the Notes to Consolidated Condensed Financial Statements in this report, as well as Note Q -- Commitments and Contingencies in our 2006 Annual Report on Form 10-K.

Interest Expense

Our interest expense increased by $3.5 million, or 16.9%, for the third quarter of 2007, when compared to the same period in 2006. This increase reflects an increase in long-term debt outstanding. In addition, we have lower capitalized interest due to a lower average balance of construction projects in 2007.

Income Taxes

For the third quarter of 2007, our effective tax rate was 39.2% compared with a 38.6% rate during the third quarter of 2006.

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

EARNINGS

We had net income of $211.2 million for the first nine months of 2007, a decrease of $11.3 million, or 5.1%, from the first nine months of 2006. The decrease primarily reflects the timing of fuel and purchased power costs and recoveries of these costs during the first nine months of 2007 compared with the first nine months of 2006. Nuclear and coal outages during the first nine months of 2007 reduced our electric generation, increasing our average cost of generation and forcing us to replace that lost generation with more expensive natural gas-fired generation and purchased power. This reduction to net income was partially offset by more favorable weather during the first nine months of 2007 compared to the same period in 2006, which increased total retail sales. In addition, during the first nine months of 2007, we recorded the settlement of a billing dispute and gains on the land sales in Northern Wisconsin and the Upper Peninsula of Michigan. A more detailed analysis of our fina ncial results follows.

Electric Utility Revenues and Sales

The following table compares our electric utility operating revenues and MWh sales by customer class during the first nine months of 2007 with the first nine months of 2006 including favorable (better (B)) or unfavorable (worse (W)) variances.

	Nine Months Ended September 30

	Electric Revenues			MWh Sales

	2007	B(W)	2006	2007	B(W)		2006

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$690.6	$45.4	$645.2	6,345.5	223.3			6,122.2
Small Commercial/Industrial	636.3	41.1	595.2	6,956.3	199.5			6,756.8
Large Commercial/Industrial	509.8	31.3	478.5	8,356.1	8.5			8,347.6
Other-Retail	14.1	0.6	13.5	118.0	(1.0	)		119.0

Total Retail Sales	1,850.8	118.4	1,732.4	21,775.9	430.3			21,345.6
Wholesale-Other	63.8	13.1	50.7	1,413.3	32.4			1,380.9
Resale-Utilities	67.6	1.4	66.2	1,071.4	(207.9	)		1,279.3
Other Operating Revenues	31.8	2.7	29.1	-	-			-

Total	$2,014.0	$135.6	$1,878.4	24,260.6	254.8			24,005.8




Weather -- Degree Days (a)
Heating (4,309 Normal)				4,259	425			3,834
Cooling (714 Normal)				755	35			720

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

During the first nine months of 2007, electric utility operating revenues increased by $135.6 million, or approximately 7.2%, when compared to the first nine months of 2006. The most significant increase in revenues relates to the recognition of revenues attributable to fuel and purchased power. Our policy for electric fuel revenues is to not recognize revenue for any currently billable amounts if it is probable that we will refund those amounts to customers. In 2006, we experienced lower than expected fuel and purchased power costs, and we established $48.7 million of reserves to reflect amounts that we expected to refund to customers. No such reserves have been established in 2007 as we are experiencing higher fuel and purchased power costs. In addition, we estimate that $33.5 million of the increase in operating revenues relates to pricing increases. This increase primarily reflects rate increases received in late January 2006 that were in effect for the entire nine month peri od ended September 30, 2007 and the wholesale rate increase effective in May 2007. We also estimate that $13.5 million of the increase was due to more favorable weather and $22.9 million relates to sales growth in residential and commercial sales. Approximately $9.0 million of the increase relates to the settlement in the second quarter of 2007 of a billing dispute with our largest customers, two iron ore mines.

Our retail electric sales volume increased by approximately 2.0%. The increase in retail sales was driven by growth in residential and commercial sales and favorable winter weather in 2007 as compared to the same period in 2006. As measured by heating degree days, the first nine months of 2007 were 11.1% colder than the same period in 2006, increasing heating load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. The increase in retail sales was offset by a 16.3% decline in sales volumes to other utilities due to lower plant availability during the nine months ended September 30, 2007.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $132.1 million, or 22.7%, when compared to the first nine months of 2006. Our total electric sales volume increased by approximately 1.1% in the first nine months of 2007. However, our average fuel and purchased power cost per MWh also increased by $5.01, or approximately 22.2%. In the first nine months of 2007, we had a 10.5% reduction in MWh output at our nuclear units due primarily to a planned refueling outage at Point Beach during the second quarter of 2007. In 2006, the scheduled refueling outage at Point Beach occurred in the fourth quarter. Additionally, generation from our coal units was 7.6% lower in the first nine months of 2007 due primarily to coal unit outages in the first quarter of 2007 as compared to 2006. As a result of the reduced coal and nuclear output, approximately 22.7% of our MWh sales in the first nine months of 2007 were supplied by higher cost natural gas-fired generation and purchased power as compared to 15.0% in the first nine months of 2006.

For further information, 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 nine months of 2007 with the first nine months of 2006. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas margins increased by approximately $10.4 million, or 9.5%, primarily because of the new rates that went into effect at the end of January 2006.

	Nine Months Ended September 30

	2007	B (W)		2006

	(Millions of Dollars)

Gas Operating Revenues	$419.3	$13.2		$406.1
Cost of Gas Sold	299.4	(2.8	)	296.6

Gross Margin	$119.9	$10.4		$109.5

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

	Nine Months Ended September 30

	Gross Margin				Therm Deliveries

	2007	B (W)		2006	2007	B (W)	2006

	(Millions of Dollars)				(Millions)
Customer Class
Residential	$79.1	$7.0		$72.1	231.8	25.5	206.3
Commercial/Industrial	27.1	3.2		23.9	137.9	10.4	127.5
Interruptible	0.5	0.1		0.4	5.1	0.9	4.2

Total Retail Gas Sales	106.7	10.3		96.4	374.8	36.8	338.0
Transported Gas	11.5	0.2		11.3	251.0	28.9	222.1
Other	1.7	(0.1	)	1.8	-	-	-

Total	$119.9	$10.4		$109.5	625.8	65.7	560.1




Weather -- Degree Days (a)
Heating (4,309 Normal)					4,259	425	3,834

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

Our gas margins increased by $10.4 million, or 9.5%, when compared to the first nine months of 2006. We estimate that approximately $6.8 million of this increase related to increased sales as a result of more normal winter weather. The first nine months of 2007 were approximately 11.1% colder than the same period in 2006. As a result, our retail therm deliveries increased approximately 10.9% as compared to the first nine months of 2006. In addition, we estimate that our gas margins improved by approximately $2.3 million due to a rate order that went into effect in the latter part of January 2006 and was effective for the entire nine month period ended September 30, 2007.

Other Operation and Maintenance Expenses

Our other operation and maintenance expenses increased by $24.9 million, or approximately 3.1%, when compared to the first nine months of 2006. In January 2006, we received a rate order to cover increased expenses related to transmission costs, bad debt costs and PTF costs. We estimate that for the first nine months of 2007, other operation and maintenance expenses (and revenues) were approximately $11.4 million higher than the same period last year as a result of the January 2006 rate order. In the first nine months of 2007, we had a scheduled nuclear refueling outage. We did not have a similar outage in the first nine months of 2006. This resulted in an increase of approximately $17.5 million in nuclear operation and maintenance expenses between the comparative periods. This increase was offset, in part, by an $8.9 million reduction in benefit related costs and other factors.

Other Income, Net

Other income, net increased by approximately $5.1 million, or 14.0%, when compared to the nine months ended September 30, 2006. The increase reflects approximately $10.4 million of pre-tax gains on property sales in 2007 compared with pre-tax gains of approximately $1.7 million during the same period in 2006. The largest gains in 2007 relate to land sold in Northern Wisconsin and the Upper Peninsula of Michigan. We had additional capitalized carrying costs and gross receipts tax of approximately $5.4 million during the nine months ended September 30, 2007. These increases were offset, in part, by a decrease of $8.1 million in AFUDC. This reduction primarily reflects the new scrubber we put in service

at our Pleasant Prairie Power Plant during the fourth quarter of 2006. This scrubber was installed as part of our EPA consent decree spending. For further information on the consent decree with the EPA, see Note 11 -- Commitments and Contingencies in this report, as well as Note Q -- Commitments and Contingencies in our 2006 Annual Report on Form 10-K.

Interest Expense

Our interest expense increased by $6.6 million, or 10.2%, for the first nine months of 2007, when compared to the same period in 2006. This increase reflects an increase in long-term debt outstanding. In addition, we have lower capitalized interest due to a lower average balance of construction projects in 2007.

Income Taxes

For the first nine months of 2007, our effective tax rate was 39.1% compared with a 38.2% rate during the first nine months of 2006.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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

	Nine Months Ended September 30

Wisconsin Electric Power Company	2007		2006

	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$414.2		$498.0
Investing Activities	$202.4		($322.9	)
Financing Activities	($139.0	)	($183.4	)

Operating Activities

Cash provided by operating activities was $414.2 million during the nine months ended September 30, 2007, or $83.8 million lower than the comparable period in 2006. This decline was due primarily to fuel recoveries, increased deferred costs and changes in working capital requirements. In the nine months ended September 30, 2007, we had unfavorable recoveries of fuel and purchased power costs of $39.5 million. In the same period in 2006, we had favorable recoveries of fuel and purchased power costs of $56.7 million.

Investing Activities

Cash provided by investing activities increased by $525.3 million during the nine months ended September 30, 2007, compared to the same period in 2006. In September 2007, we sold Point Beach to an affiliate of FPL and received approximately $924 million. In connection with the sale, we also transferred $390 million of decommissioning funds to the buyer and retained approximately $552 million of decommissioning funds. After subtracting the book value of the plant and transaction costs, the net gain from the sale, as well as the decommissioning funds that we retained, are expected tobe used for the

benefit of our customers, as determined by ourregulators. To that end, we have placed approximately $969 million of proceeds in a separate interest bearing bank account for the benefit of our customers. We expect to use a portion of these proceeds to pay tax obligations related to the liquidation of the qualified decommissioning trust due in the fourth quarter of 2007, and to withdraw the remaining funds to offset the cash impact of bill credits that we expect to apply to our customers' bills over the next two years. We anticipate that substantially all of the $969 million of restricted cash, after the payment of related taxes, will be withdrawn to offset customer bill credits before December 31, 2009.

Financing Activities

During the first nine months of 2007, we used $139.0 million for financing activities compared with $183.4 million used for financing activities during the same period in 2006. During the first nine months of 2007 and 2006, we paid dividends on common stock of $89.8 million. During the first nine months of 2007, short-term debt increased by approximately $18.3 million, compared to a decrease in short-term debt of approximately $172.0 million for the same period in 2006, for a net increase of $190.3 million. Partially offsetting this increase in financing sources was a $100 million capital contribution received from Wisconsin Energy in April 2006. No capital contributions have been received in 2007. In addition, we paid off all of Wisconsin Electric Fuel Trust's outstanding commercial paper, aggregating $76.2 million.

CAPITAL RESOURCES AND REQUIREMENTS

Capital Resources

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

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

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

We have a credit agreement that provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes.

As of September 30, 2007, we had approximately $495.9 million of available unused lines under our bank back-up credit facility and approximately $322.5 million of total consolidated short-term debt outstanding.

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

Total Facility	Letters of Credit	Credit Available	Facility Expiration	Facility Term

(Millions of Dollars)

$500.0	$4.1	$495.9	March 2011	5 year

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

	S&P	Moody's	Fitch


Commercial Paper	A-2	P-1	F1
Unsecured Debt	A-	A1	A+
Preferred Stock	BBB	A3	A

In July 2007, S&P affirmed our corporate credit ratings and revised our ratings outlook from negative to stable.

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

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

Capital Requirements

Capital requirements during the remainder of 2007 are expected to be principally for capital expenditures and long-term debt maturities. We expect to retire at the scheduled maturity date, $250 million of 3.50% debentures due December 1, 2007. Our 2007 annual capital expenditure budget, excluding the purchase of nuclear fuel, is approximately $600 million.

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

Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support 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 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 2006 Annual Report on Form 10-K. We have included our contractual obligations under all three of these contracts in our evaluation of Contractual Obligations/Commercial Commitments discussed below.

Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments increased to approximately $18.4 billion as of September 30, 2007 compared with $6.9 billion as of December 31, 2006. This increase was due primarily to the implementation of the Point Beach Nuclear Plant Power Purchase Agreement, which is a 26 year agreement, and agreements entered into in connection with our wind generation project. This increase was offset, in part, by assigning obligations related to Point Beach to an affiliate of FPL as part of the sale of Point Beach. In addition, we made periodic payments related to these types of obligations in the ordinary course of business during the nine months ended September 30, 2007.

FACTORS AFFECTING RESULTS, LIQUDITY AND CAPITAL RESOURCES

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

POWER THE FUTURE

Under 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 plants 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 2006 Annual Report on Form 10-K for additional information on PTF.

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

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

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

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

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

RATES AND REGULATORY MATTERS

2008 Rate Case

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

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

The proposed net price increase for electric customers in Wisconsin reflects credits expected to be applied from the sale of Point Beach. In our May 2007 filing, we anticipated that there would be approximately $653 million of credits available for Wisconsin customers. Now, we anticipate that there are approximately $696 million of proceeds from the sale of Point Beach to offset the required price increases in Wisconsin. Our proposed plan, if approved by the PSCW, would apply $107 million to recover existing regulatory assets in 2008. Our plan would provide monthly bill credits of approximately $372 million in 2008 and $188 million, including interest, in 2009, and any remaining proceeds in our next scheduled rate filing. The proposed credits are expected to have a significant impact on net price increases for electric customers. For example, a $50 million increase or decrease in the pricing credits provided in 2008, while leaving the other components of our propos al unchanged, would result in a corresponding decrease or increase of approximately 2.5% in the net price change to electric customers in

2008. The new prices, which will be subject to a full review by the PSCW, are expected to be implemented in January 2008.

2006 Rate Order

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

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

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

Gas Rates: Our gas operations went through a traditional rate proceeding whereby the revenues were set to recover projected costs and to provide a return on rate base. The January 2006 order provided for an increase in gas revenues of $21.4 million annually, or 2.9%, which was based on an authorized return on equity of 11.2%.

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

Limited Rate Adjustment Requests

2005 Fuel Recovery Filing: In February 2005, we filed an application with the PSCW for an increase in electric rates in the amount of $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in our reliance upon natural gas as a fuel source. We received approval for the increase in fuel recoveries on an interim basis in March 2005. In November 2005, we received the final rate order, which authorized an additional $7.7 million in rate increases, for a total increase of $122.6 million (6.2%). In December 2005, two parties filed suit against the PSCW in Dane County Circuit Court challenging the PSCW's decision to allow fuel cost recovery, while allowing us to keep the savings that resulted from Wisconsin Energy's acquisition of WICOR, Inc.. As a condition of the PSCW approval of the WICOR acquisition, we were restricted from increasing our Wisconsin rates for a five year period endi ng December 31, 2005, with certain limited exceptions, but we were allowed to keep the savings generated from the merger. In July 2006, the Dane County Circuit Court affirmed the PSCW's decision. In August 2006, the opponents appealed this decision to the Wisconsin Court of Appeals. In July 2007, the Court of Appeals affirmed the Dane County Circuit Court decision upholding the PSCW's order. The time period for further appeal has expired and no appeal was filed.

Other Regulatory Matters

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

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

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

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

WIND GENERATION

In June 2005, we purchased the development rights to two wind farm projects (Blue Sky Green Field) from Navitas Energy Inc. In March 2006, we filed for approval of a CPCN with the PSCW. Hearings were held at the end of November 2006. In February 2007, the PSCW issued a written notice approving the CPCN. During March 2007, we entered into a final agreement with Vestas Wind Systems for the purchase of wind turbines with a combined generating capacity of 145 MW. In May 2007, we entered into an agreement with Alliant Energy EPC, LLC to construct the wind farm. In addition to the CPCN approval, we secured other required permits, including all requested Federal Aviation Administration permits, and began construction in June 2007.Equipment is expected to begin arriving at the site during the fourth quarter of 2007. We have also entered into service and warranty agreements with Vestas Wind Systems that will co ver the first two years of operation. We estimate that the capital cost of the project, excluding AFUDC, will be approximately $300 million. We currently expect the turbines to be placed into service no later than the second quarter of 2008.

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

NUCLEAR OPERATIONS

In September 2007, we sold Point Beach to an affiliate of FPL for approximately $924 million. Upon closing of the sale, the power purchase agreement became effective for the existing energy and capacity produced by Point Beach. See Note 3 -- Sale of Point Beach in the Notes to Consolidated Condensed Financial Statements in this report and Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding the sale of Point Beach.

ELECTRIC TRANSMISSION

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

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

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

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

ENVIRONMENTAL MATTERS

entered it in October 2007. For additional information, see Note 11 -- Commitments and Contingencies in the Notes to Consolidated Condensed Financial Statements in this report.

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

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

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

National Ambient Air Quality Standards:

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

PM_2.5Standard: In December 2006, a more restrictive federal standard became effective, which may place some counties in Southeastern Wisconsin into non-attainment status. This standard is currently being litigated. Until such time as the states develop rules and submit State Implementation Plans to EPA to demonstrate how they intend to comply with the standard, we are unable to predict the impact of this more restrictive standard on the operation of our existing coal-fired generation facilities or Wisconsin Energy's new PTF generating units.

Clean Air Interstate Rule: The EPA issued the final CAIR regulation in March 2005 to facilitate the states in meeting the 8-hour ozone and PM_2.5 standards by addressing the regional transport of SO₂ and NO_x. The states were required to develop and submit implementation plans by no later than March 2007. A final CAIR rule has been adopted in Wisconsin and Michigan. We believe that compliance with the NO_x and SO₂ emission reductions requirements under the agreement with the EPA will substantially mitigate costs to comply with the CAIR rule.

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information concerning market risk exposures at Wisconsin 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 2006 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures: Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based upon such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Fina ncial 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 2006 Annual Report on Form 10-K and Item 1. Legal Proceedings in Part II of our Quarterly Report on Form 10-Q for the periods ended March 31 and June 30, 2007.

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

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 2006 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

ITEM 6. EXHIBITS

Exhibit No.


2	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

2.1	Letter Agreement between Wisconsin Electric Power Company, FPL Energy Point Beach, LLC and FPL Group Capital, Inc., dated September 28, 2007, which amends the Asset Sale Agreement between the parties. (Exhibit 2.3 to Wisconsin Energy Corporation's 9/28/07 Form 8-K (File No. 001-09057).)

10	Material Contracts

10.1	2007 Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan, as amended. (Exhibit 10.1 to Wisconsin Energy Corporation's 9/30/07 Form 10-Q (File No. 001-09057).)

10.2	Wisconsin Energy Corporation Performance Unit Plan, amended and restated effective as of October 11, 2007. (Exhibit 10.2 to Wisconsin Energy Corporation's 9/30/07 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: November 1, 2007	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Good

Wisconsin Electric Power Company PFD 3.60% (WELPP) 10-Q2007 Q3 Quarterly report

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