WISCONSIN ELECTRIC POWER CO - Quarter Report: 2013 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2013



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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T

(§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]

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

Large accelerated filer [ ] Accelerated filer [ ]

Non-accelerated filer [X] (Do not Smaller reporting company [ ]

check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (September 30, 2013):



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.

Form 10-Q

WISCONSIN ELECTRIC POWER COMPANY

_________________________

FORM 10-Q REPORT FOR THE QUARTER ENDED SEPTEMBER 30, 2013



	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	21

3.	Quantitative and Qualitative Disclosures About Market Risk	34

4.	Controls and Procedures	34

	Part II -- Other Information

1.	Legal Proceedings	34

1A.	Risk Factors	35

6.	Exhibits	36

	Signatures	37



September 2013	2	Wisconsin Electric Power Company

Form 10-Q



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:

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

Significant Assets
PIPP		Presque Isle Power Plant
PSGS		Paris Generating Station
VAPP		Valley Power Plant

Other Affiliates
ATC		American Transmission Company LLC

Federal and State Regulatory Agencies
DOE		United States Department of Energy
DOJ		Wisconsin Department of Justice
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Environmental Terms
CAIR		Clean Air Interstate Rule
CSAPR		Cross-State Air Pollution Rule
MATS		Mercury and Air Toxics Standards
NOV		Notice of Violation
NO_X		Nitrogen Oxide
SO₂		Sulfur Dioxide

Other Terms and Abbreviations
AQCS		Air Quality Control System
ARRs		Auction Revenue Rights
Bechtel		Bechtel Power Corporation
Compensation Committee		Compensation Committee of the Board of Directors of Wisconsin Energy
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
LMP		Locational Marginal Price
MISO		Midcontinent Independent System Operator, Inc.
OTC		Over-the-Counter
PTF		Power the Future
RTO		Regional Transmission Organization



September 2013	3	Wisconsin Electric Power Company

Form 10-Q



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:

SSR		System Support Resource
Wolverine		Wolverine Power Supply Cooperative, Inc.

Measurements
Btu		British Thermal Unit(s)
Dth		Dekatherm(s) (One Dth equals one million Btu)
GWh		Gigawatt-hour(s) (One GWh equals one thousand MWh)
MW		Megawatt(s) (One MW equals one million Watts)
MWh		Megawatt-hour(s)
Watt		A measure of power production or usage

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
ASU		Accounting Standards Update
GAAP		Generally Accepted Accounting Principles
OPEB		Other Post-Retirement Employee Benefits



September 2013	4	Wisconsin Electric Power Company

Form 10-Q

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements contained in this report are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of construction projects, regulatory matters, on-going legal proceedings, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets" 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 catastrophic weather-related or terrorism-related damage; cyber-security threats and disruptions to our technology network; 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; unanticipated changes in the cost or availability of materials needed to operate new environmental controls at our electric generating facilities or replace and/or repair our electric and gas distribution systems; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; environmental incidents; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; or collective bargaining agreements with union employees or work stoppages.


•	Factors affecting the demand for electricity and natural gas, including weather and other natural phenomena; general economic conditions and, in particular, the economic climate in our service territories; customer growth and declines; customer business conditions, including demand for their products and services; energy conservation efforts; and customers moving to self-generation.

•

Timing, resolution and impact of current and future rate cases and negotiations, including recovery of costs associated with environmental compliance, renewable generation, transmission service, distribution system upgrades, fuel and the Midcontinent Independent System Operator, Inc. (MISO) Energy Markets, as well as any costs incurred as a result of customers moving to an alternative electric supplier.


•	Increased competition in our electric and gas markets, including retail choice and alternative electric suppliers, and continued industry consolidation.


•	Our ability to mitigate the impact of Michigan customers switching to an alternative electric supplier.


•	The ability to control costs and avoid construction delays during the development and construction of new environmental controls and renewable generation, as well as upgrades to our electric and natural gas distribution systems.

•

The impact of recent and future federal, state and local legislative and regulatory changes, including any changes in rate-setting policies or procedures; cuts in funding of the U.S. Treasury Department's 1603 grant program for renewable energy projects under the National Defense Authorization Act; electric and gas industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; any required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities or cybersecurity threats; required approvals for new construction, and the siting approval process for new generation and transmission facilities and new pipeline construction; changes to the Federal Power Act and related regulations and enforcement thereof by the Federal Energy Regulatory Commission (FERC) and other



September 2013	5	Wisconsin Electric Power Company

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION -- (CONT'D) Form 10-Q

regulatory agencies; changes in allocation of energy assistance, including state public benefits funds; changes in environmental, tax and other laws and regulations to which we are subject; changes in the application of existing laws and regulations; and changes in the interpretation or enforcement of permit conditions by the permitting agencies.


•	Internal restructuring options that may be pursued by Wisconsin Energy Corporation (Wisconsin Energy).


•	Current and future litigation, regulatory investigations, proceedings or inquiries, including FERC matters and Internal Revenue Service audits and other tax matters.


•	Events in the global credit markets that may affect the availability and cost of capital.


•	Other factors affecting our ability to access the capital markets, including general capital market conditions; our capitalization structure; market perceptions of the utility industry or us; and our credit ratings.


•	Inflation rates.


•	The investment performance of Wisconsin Energy's pension and other post-retirement benefit trusts.


•	The financial performance of American Transmission Company LLC (ATC) and its corresponding contribution to our earnings.


•	The impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act and any regulations promulgated thereunder.


•	The impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 and any related regulations.


•	The effect of accounting pronouncements issued periodically by standard setting bodies, including any changes in regulatory accounting policies and practices and any requirement for U.S. registrants to follow International Financial Reporting Standards instead of Generally Accepted Accounting Principles (GAAP).


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


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


•	The ability to obtain and retain short- and long-term contracts with wholesale customers.


•	Potential strategic business opportunities, including acquisitions and/or dispositions of assets or businesses, which we cannot ensure will be beneficial for us.


•	Incidents affecting the U.S. electric grid or operation of generating facilities.


•	Foreign governmental, economic, political and currency risks.


•	Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission (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, 2012 as updated in Item 1A. Risk Factors in Part II of this report.

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



September 2013	6	Wisconsin Electric Power Company

Form 10-Q

INTRODUCTION

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

We conduct our operations primarily in three reportable segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,126,200 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 469,600 gas customers in Wisconsin and approximately 450 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our reportable segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 8 --Segment Information in the Notes to Consolidated Condensed Financial Statements in this report.

Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas), a natural gas distribution utility, which serves customers throughout Wisconsin; and W.E. Power, LLC (We Power), an unregulated company that was formed in 2001 to design, construct, own and lease to us the new generating capacity included in Wisconsin Energy's Power the Future (PTF) strategy, which is described further in this report and in our 2012 Annual Report on Form 10-K. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies."

Bostco is our non-utility subsidiary that develops and invests in real estate. As of September 30, 2013, Bostco had $29.3 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 2012 Annual Report on Form 10-K, including the financial statements and notes therein.



September 2013	7	Wisconsin Electric Power Company

Form 10-Q

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
	2013		2012		2013		2012
	(Millions of Dollars)

Operating Revenues	$	964.6	$	951.9	$	2,849.7	$	2,739.1

Operating Expenses
Fuel and purchased power	340.4		337.7		890.1		852.8
Cost of gas sold	24.4		22.0		184.1		154.1
Other operation and maintenance	338.0		305.7		1,023.1		959.7
Depreciation and amortization	69.5		65.0		207.4		190.0
Property and revenue taxes	27.7		28.2		83.1		84.6
Total Operating Expenses	800.0		758.6		2,387.8		2,241.2

Operating Income	164.6		193.3		461.9		497.9

Equity in Earnings of Transmission Affiliate	15.1		15.0		44.9		43.0
Other Income, net	4.6		8.8		14.1		32.7
Interest Expense, net	29.3		27.5		91.5		80.7

Income Before Income Taxes	155.0		189.6		429.4		492.9

Income Tax Expense	55.8		67.1		152.4		171.2

Net Income	99.2		122.5		277.0		321.7

Preferred Stock Dividend Requirement	0.3		0.3		0.9		0.9

Earnings Available for Common Stockholder	$	98.9	$	122.2	$	276.1	$	320.8

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



September 2013	8	Wisconsin Electric Power Company

Form 10-Q



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
	September 30, 2013			December 31, 2012
	(Millions of Dollars)
Assets
Property, Plant and Equipment
In service	$	9,764.1		$	9,568.9
Accumulated depreciation	(3,223.7		)	(3,117.0		)
	6,540.4			6,451.9
Construction work in progress	379.5			289.1
Leased facilities, net	2,303.9			2,340.2
Net Property, Plant and Equipment	9,223.8			9,081.2
Investments
Equity investment in transmission affiliate	348.8			332.6
Other	0.2			0.3
Total Investments	349.0			332.9
Current Assets
Cash and cash equivalents	17.1			34.1
Accounts receivable, net	261.1			226.3
Accounts receivable from related parties	14.3			6.1
Accrued revenues	149.8			213.8
Materials, supplies and inventories	299.0			312.2
Current deferred tax asset, net	81.3			4.1
Prepayments and other	140.4			197.4
Total Current Assets	963.0			994.0
Deferred Charges and Other Assets
Regulatory assets	1,472.0			1,452.2
Other	147.0			162.3
Total Deferred Charges and Other Assets	1,619.0			1,614.5
Total Assets	$	12,154.8		$	12,022.6
Capitalization and Liabilities
Capitalization
Common equity	$	3,426.9		$	3,366.4
Preferred stock	30.4			30.4
Long-term debt	2,166.8			2,216.7
Capital lease obligations	2,719.5			2,703.1
Total Capitalization	8,343.6			8,316.6
Current Liabilities
Long-term debt and capital lease obligations due currently	373.7			357.0
Short-term debt	26.5			105.5
Subsidiary note payable to Wisconsin Energy	22.8			23.4
Accounts payable	254.4			306.8
Accounts payable to related parties	84.2			93.4
Accrued payroll and benefits	83.3			75.4
Other	130.3			110.2
Total Current Liabilities	975.2			1,071.7
Deferred Credits and Other Liabilities
Regulatory liabilities	585.0			600.3
Deferred income taxes - long-term	1,750.2			1,533.6
Pension and other benefit obligations	284.2			189.2
Other	216.6			311.2
Total Deferred Credits and Other Liabilities	2,836.0			2,634.3
Total Capitalization and Liabilities	$	12,154.8		$	12,022.6

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



September 2013	9	Wisconsin Electric Power Company

Form 10-Q



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

	Nine Months Ended September 30
	2013			2012
	(Millions of Dollars)
Operating Activities
Net income	$	277.0		$	321.7
Reconciliation to cash
Depreciation and amortization	214.1			196.7
Deferred income taxes and investment tax credits, net	145.5			211.3
Contributions to qualified benefit plans	—			(92.9		)
Change in - Accounts receivable and accrued revenues	17.0			58.5
Inventories	13.2			33.8
Other current assets	36.9			42.0
Accounts payable	(49.3		)	(47.8		)
Accrued income taxes, net	24.4			28.8
Other current liabilities	17.1			(4.8		)
Other, net	43.4			(102.9		)
Cash Provided by Operating Activities	739.3			644.4

Investing Activities
Capital expenditures	(363.6		)	(385.5		)
Investment in transmission affiliate	(6.9		)	(11.5		)
Change in restricted cash	2.7			36.0
Other, net	(37.8		)	(43.0		)
Cash Used in Investing Activities	(405.6		)	(404.0		)

Financing Activities
Dividends paid on common stock	(230.0		)	(134.7		)
Dividends paid on preferred stock	(0.9		)	(0.9		)
Issuance of long-term debt	250.0			—
Retirement of long-term debt	(300.0		)	—
Change in total short-term debt	(79.6		)	(105.4		)
Other, net	9.8			—
Cash Used in Financing Activities	(350.7		)	(241.0		)

Change in Cash and Cash Equivalents	(17.0		)	(0.6		)

Cash and Cash Equivalents at Beginning of Period	34.1			12.7

Cash and Cash Equivalents at End of Period	$	17.1		$	12.1

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



September 2013	10	Wisconsin Electric Power Company

Form 10-Q

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 2012 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three and nine months ended September 30, 2013 are not necessarily indicative of the results which may be expected for the entire fiscal year 2013 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Offsetting Assets and Liabilities: In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2011-11, Disclosures about Offsetting Assets and Liabilities. The guidance requires enhanced disclosures about derivatives. Both gross and net information related to eligible transactions is required under the guidance. This guidance is effective for fiscal years and interim periods beginning on or after January 1, 2013, and must be applied retrospectively. We adopted this guidance on January 1, 2013, and applied it retrospectively. The adoption and retrospective application of this guidance did not have any material impact on our financial statements. See Note 6 -- Derivative Instruments for the enhanced disclosures.

3 -- COMMON EQUITY

Stock Option Activity: The following table identifies non-qualified stock options granted by the Compensation Committee of the Board of Directors (Compensation Committee):



	2013			2012

Non-qualified stock options granted year to date	1,365,970			903,865
Estimated fair value per non-qualified stock option	$	3.45		$	3.34
Assumptions used to value the options using a binomial option pricing model:
Risk-free interest rate	0.1% - 1.9%			0.1% - 2.0%
Dividend yield	3.7		%	3.9		%
Expected volatility	18.0		%	19.0		%
Expected forfeiture rate	2.0		%	2.0		%
Expected life (years)	5.9			5.9

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.



September 2013	11	Wisconsin Electric Power Company

Form 10-Q

The following is a summary of Wisconsin Energy stock option activity by our employees during the three and nine months ended September 30, 2013:



					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of July 1, 2013	8,056,421		$	26.62
Granted	—		$	—
Exercised	(78,806	)	$	21.41
Forfeited	(4,680	)	$	35.36
Outstanding as of September 30, 2013	7,972,935		$	26.66

Outstanding as of January 1, 2013	8,416,876		$	23.96
Granted	1,365,970		$	37.46
Exercised	(1,799,881	)	$	22.19
Forfeited	(10,030	)	$	35.37
Outstanding as of September 30, 2013	7,972,935		$	26.66	5.5	$	109.4

Exercisable as of September 30, 2013	5,683,535		$	23.03	4.2	$	98.6

The intrinsic value of Wisconsin Energy options exercised by our employees was $1.7 million and $34.9 million for the three and nine months ended September 30, 2013 and $7.8 million and $38.7 million for the same periods in 2012, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $39.9 million and $42.0 million for the nine months ended September 30, 2013 and 2012, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was $14.0 million and zero, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of September 30, 2013:



	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
				Remaining				Remaining
	Number of	Exercise		Contractual	Number of	Exercise		Contractual
Range of Exercise Prices	Options	Price		Life (Years)	Options	Price		Life (Years)
$16.72 to $21.11	2,246,130	$	20.27	3.9	2,246,130	$	20.27	3.9
$23.88 to $29.35	3,539,460	$	24.65	4.5	3,246,200	$	24.23	4.2
$34.87 to $37.46	2,187,345	$	36.48	8.9	191,205	$	35.14	8.4
	7,972,935	$	26.66	5.5	5,683,535	$	23.03	4.2



September 2013	12	Wisconsin Electric Power Company

Form 10-Q

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the three and nine months ended September 30, 2013:



			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of July 1, 2013	2,294,780		$	3.38
Granted	—		$	—
Vested	(700	)	$	3.17
Forfeited	(4,680	)	$	3.37
Non-vested as of September 30, 2013	2,289,400		$	3.38

Non-vested as of January 1, 2013	1,637,570		$	3.31
Granted	1,365,970		$	3.45
Vested	(704,110	)	$	3.33
Forfeited	(10,030	)	$	3.37
Non-vested as of September 30, 2013	2,289,400		$	3.38

As of September 30, 2013, our total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $2.9 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Restricted Shares: The following restricted stock activity related to our employees occurred during the three and nine months ended September 30, 2013:



			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2013	98,457
Granted	—		$	—
Released	—		$	—
Forfeited	(231	)	$	34.48
Outstanding as of September 30, 2013	98,226

Outstanding as of January 1, 2013	126,392
Granted	53,055		$	37.71
Released	(67,722	)	$	26.77
Forfeited	(13,499	)	$	33.30
Outstanding as of September 30, 2013	98,226

Wisconsin Energy records the market value of the restricted stock awards on the date of grant and then we amortize our share of allocated expense over the vesting period of the awards. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was zero and $2.8 million for the three and nine months ended September 30, 2013, and zero and $1.9 million for the same periods in 2012, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was zero and $1.1 million for the three and nine months ended September 30, 2013, and zero for the same periods in 2012, respectively.

As of September 30, 2013, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $2.4 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Performance Units: In January 2013 and 2012, the Compensation Committee awarded 230,245 and 333,685 Wisconsin Energy performance units, respectively, to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Performance units earned as of December 31, 2012 and 2011 vested and were settled during the first quarter of 2013 and 2012, and had a total intrinsic value of $17.1 million and $26.1 million,



September 2013	13	Wisconsin Electric Power Company

Form 10-Q

respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $6.2 million and $9.6 million, respectively. As of September 30, 2013, total compensation cost related to our share of Wisconsin Energy performance units not yet recognized was approximately $11.4 million, which is expected to be recognized over the next 20 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 H -- Common Equity in our 2012 Annual Report on Form 10-K for additional information on these and other restrictions.

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

4 -- LONG-TERM DEBT

In June 2013, we issued $250 million of 1.70% Debentures due June 15, 2018. The debentures were issued under an existing shelf registration statement filed with the SEC in February 2011. The net proceeds were used to repay short-term debt and for other corporate purposes.

On May 15, 2013, we used short-term borrowings to retire $300 million of long-term debt that matured.

5 -- FAIR VALUE MEASUREMENTS

Fair value measurements require enhanced disclosures about assets and liabilities that are measured and reported at fair value and establish a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value.

Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. Accordingly, we also utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities measured and reported at fair value are classified and disclosed in one of the following categories:

Level 1 -- Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments.

Level 2 -- Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as Over-the-Counter (OTC) forwards and options.

Level 3 -- Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to fair value reporting and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is



September 2013	14	Wisconsin Electric Power Company

Form 10-Q

significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.

The following tables summarize our financial assets and liabilities by level within the fair value hierarchy:



Recurring Fair Value Measures	As of September 30, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	—	$	—	$	—	$	—
Derivatives	1.2		3.7		5.6		10.5
Total	$	1.2	$	3.7	$	5.6	$	10.5

Liabilities:
Derivatives	$	1.1	$	0.1	$	—	$	1.2
Total	$	1.1	$	0.1	$	—	$	1.2



Recurring Fair Value Measures	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	2.7	$	—	$	—	$	2.7
Derivatives	1.2		11.5		4.7		17.4
Total	$	3.9	$	11.5	$	4.7	$	20.1

Liabilities:
Derivatives	$	1.1	$	—	$	—	$	1.1
Total	$	1.1	$	—	$	—	$	1.1

We adopted ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, on a retrospective basis. For additional information, see Note 2 -- New Accounting Pronouncements and Note 6 -- Derivative Instruments.

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents the settlement we received from the United States Department of Energy (DOE) during the first quarter of 2011, which was returned, net of costs incurred, to customers. Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

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



September 2013	15	Wisconsin Electric Power Company

Form 10-Q



	Three Months Ended September 30						Nine Months Ended September 30
	2013			2012			2013			2012
	(Millions of Dollars)

Beginning Balance	$	9.2		$	9.9		$	4.7		$	5.7
Realized and unrealized gains (losses)	—			—			—			—
Purchases	—			—			10.6			10.9
Issuances	—			—			—			—
Settlements	(3.6		)	(2.6		)	(9.7		)	(9.3		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of September 30	$	5.6		$	7.3		$	5.6		$	7.3

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

Derivative instruments reflected in Level 3 of the hierarchy include MISO Financial Transmission Rights (FTRs) that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet. See Note 6 -- Derivative Instruments for further information on the offset to regulatory assets and liabilities.

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



	September 30, 2013				December 31, 2012
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	26.3	$	30.4	$	26.0
Long-term debt, including current portion	$	2,487.0	$	2,652.0	$	2,537.0	$	2,900.8

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

6 -- DERIVATIVE INSTRUMENTS

We utilize derivatives as part of our risk management program to manage the volatility and costs of purchased power, generation and natural gas purchases for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the Public Service Commission of Wisconsin (PSCW).

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of September 30, 2013, we recognized $2.5 million in regulatory assets and $9.8 million in regulatory liabilities related to derivatives in comparison to $3.7 million in regulatory assets and $16.7 million in regulatory liabilities as of December 31, 2012.

We record our current derivative assets on the balance sheet in prepayments and other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $0.7 million is recorded in other deferred charges and other assets as of September 30, 2013, and the long-term



September 2013	16	Wisconsin Electric Power Company

Form 10-Q

portion of our derivative liabilities of $0.2 million is recorded in other deferred credits and other liabilities as of September 30, 2013. Our Consolidated Condensed Balance Sheets as of September 30, 2013 and December 31, 2012 include:



	September 30, 2013				December 31, 2012
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	1.2	$	1.2	$	1.2	$	1.1
Fuel Oil	0.3		—		0.4		—
FTRs	5.6		—		4.7		—
Coal	3.4		—		11.1		—
Total	$	10.5	$	1.2	$	17.4	$	1.1

Our Consolidated Condensed Income Statements include gains (losses) on derivative instruments used in our risk management strategies under fuel and purchased power for those commodities supporting our electric operations and under cost of gas sold for the natural gas sold to our customers. Our estimated notional volumes and gains (losses) were as follows:



	Three Months Ended September 30, 2013				Three Months Ended September 30, 2012
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)

Natural Gas	3.6 million Dth	$	(0.5	)	9.4 million Dth	$	(2.5	)
Fuel Oil	2.5 million gallons	(0.1		)	1.7 million gallons	0.1
FTRs	6,322 MW	5.4			5,927 MW	2.9
Total		$	4.8			$	0.5



	Nine Months Ended September 30, 2013				Nine Months Ended September 30, 2012
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)

Natural Gas	18.2 million Dth	$	(2.6	)	27.4 million Dth	$	(16.9	)
Fuel Oil	6.2 million gallons	0.1			5.5 million gallons	1.5
FTRs	17,410 MW	11.0			16,581 MW	5.1
Total		$	8.5			$	(10.3	)

As of September 30, 2013 and December 31, 2012, we posted collateral of $1.9 million and $2.1 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

The fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. The table below shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet as of September 30, 2013 and December 31, 2012.



September 2013	17	Wisconsin Electric Power Company

Form 10-Q



	September 30, 2013						December 31, 2012
	Derivative			Derivative			Derivative			Derivative
	Asset			Liability			Asset			Liability
	(Millions of Dollars)

Gross Amount Recognized on the Balance Sheet	$	10.5		$	1.2		$	17.4		$	1.1
Gross Amount Not Offset on Balance Sheet (a)	(0.3		)	(1.0		)	(0.4		)	(1.1		)
Net Amount	$	10.2		$	0.2		$	17.0		$	—


(a)	Gross Amount Not Offset on Balance Sheet includes cash collateral posted of $0.8 million and $0.6 million as of September 30, 2013 and December 31, 2012, respectively.

7 -- BENEFITS

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



	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2013			2012			2013			2012
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	3.5		$	4.9		$	10.4		$	14.8
Interest cost	13.1			14.2			39.3			42.6
Expected return on plan assets	(19.3		)	(17.9		)	(57.9		)	(53.8		)
Amortization of:
Prior service cost	0.5			0.5			1.6			1.6
Actuarial loss	10.4			7.6			31.3			22.6
Net Periodic Benefit Cost	$	8.2		$	9.3		$	24.7		$	27.8



	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2013			2012			2013			2012
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.4		$	2.5		$	7.1		$	7.4
Interest cost	3.2			4.2			9.5			12.6
Expected return on plan assets	(3.7		)	(3.3		)	(10.9		)	(9.8		)
Amortization of:
Transition obligation	—			—			—			0.2
Prior service (credit)	(0.5		)	(0.5		)	(1.4		)	(1.4		)
Actuarial loss	0.4			1.3			1.1			3.7
Net Periodic Benefit Cost	$	1.8		$	4.2		$	5.4		$	12.7

During the first nine months of 2013 and 2012, we contributed zero and $92.9 million, respectively, to our qualified benefit plans. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates.



September 2013	18	Wisconsin Electric Power Company

Form 10-Q

Postemployment Benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $2.4 million as of September 30, 2013 and December 31, 2012.

8 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable segments for the three and nine months ended September 30, 2013 and 2012 is shown in the following table:



	Reportable Segments
	Electric		Gas			Steam			Total
	(Millions of Dollars)
Three Months Ended

September 30, 2013
Operating Revenues (a)	$	911.0	$	48.0		$	5.6		$	964.6
Operating Income (Loss)	$	168.6	$	(1.7	)	$	(2.3	)	$	164.6

September 30, 2012
Operating Revenues (a)	$	901.2	$	45.4		$	5.3		$	951.9
Operating Income (Loss)	$	193.9	$	1.9		$	(2.5	)	$	193.3

Nine Months Ended

September 30, 2013
Operating Revenues (a)	$	2,516.5	$	304.6		$	28.6		$	2,849.7
Operating Income	$	415.4	$	44.6		$	1.9		$	461.9

September 30, 2012
Operating Revenues (a)	$	2,451.1	$	263.3		$	24.7		$	2,739.1
Operating Income (Loss)	$	470.1	$	30.2		$	(2.4	)	$	497.9


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

9 -- VARIABLE INTEREST ENTITIES

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Certain disclosures are required by sponsors, significant interest holders in variable interest entities and potential variable interest entities.

We assess our relationships with potential variable interest entities such as our coal suppliers, natural gas suppliers, coal and gas transporters, and other counterparties in power purchase agreements and joint ventures. In making this assessment, we consider the potential that our contracts or other arrangements provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of the entity, the ability to directly or indirectly make decisions about the entities' activities and other factors.

We have identified a purchased power agreement which represents a variable interest. This agreement is for 236 MW of firm capacity from a gas-fired cogeneration facility and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately nine years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.



September 2013	19	Wisconsin Electric Power Company

Form 10-Q

We have approximately $226.0 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under contracts considered variable interests for the nine months ended September 30, 2013 and 2012 were $37.8 million and $44.5 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

10 -- COMMITMENTS AND CONTINGENCIES

Environmental Matters: We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, 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.

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal combustion product disposal sites. We perform ongoing assessments of our manufactured gas plant sites and related disposal sites, as well as our coal combustion product disposal/landfill sites. We are working with the Wisconsin Department of Natural Resources (WDNR) in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Manufactured Gas Plant Sites: We have identified several sites at which we or a predecessor company historically owned or operated a manufactured gas plant. These sites have been substantially remediated or are at various stages of investigation, monitoring and remediation. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon on-going analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $6 million to $18 million over the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of September 30, 2013, we have established reserves of $7.2 million related to future remediation costs.

Historically, the PSCW has allowed Wisconsin utilities, including us, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.

Divested Assets: Pursuant to the sale of the Point Beach Nuclear Power Plant, we agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp. in connection with the sale of our interest in Edgewater Generating Unit 5.

11 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the nine months ended September 30, 2013, we paid $66.6 million in interest, net of amounts capitalized, and received $35.0 million in net refunds from income taxes. During the nine months ended September 30, 2012, we paid $54.1 million in interest, net of amounts capitalized, and paid $14.7 million in income taxes, net of refunds.

As of September 30, 2013 and 2012, the amount of accounts payable related to capital expenditures was $3.3 million and $25.3 million, respectively.

During the nine months ended September 30, 2013 and 2012, our equity in earnings from ATC was $44.9 million and $43.0 million, respectively. During the nine months ended September 30, 2013 and 2012, distributions received from ATC were $35.5 million and $34.3 million, respectively.



September 2013	20	Wisconsin Electric Power Company

Form 10-Q

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

AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 2013

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the third quarter of 2013 with the third quarter of 2012, including favorable (better (B)) or unfavorable (worse (W)) variances:



	Three Months Ended September 30
	Electric Revenues							MWh Sales
Electric Utility Operations	2013		B (W)			2012		2013	B (W)		2012
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	332.7	$	(7.5	)	$	340.2	2,207.7	(214.8	)	2,422.5
Small Commercial/Industrial	287.9		3.7			284.2		2,381.6	(74.7	)	2,456.3
Large Commercial/Industrial	200.2		(0.5		)	200.7		2,326.3	(159.8	)	2,486.1
Other - Retail	5.5		0.1			5.4		34.6	—		34.6
Total Retail	826.3		(4.2		)	830.5		6,950.2	(449.3	)	7,399.5
Wholesale - Other	32.6		(7.4		)	40.0		405.8	(5.9	)	411.7
Resale - Utilities	45.4		27.6			17.8		1,430.2	833.9		596.3
Other Operating Revenues	6.7		(6.2		)	12.9		—	—		—
Total	$	911.0	$	9.8		$	901.2	8,786.2	378.7		8,407.5

Weather -- Degree Days (a)
Heating (124 Normal)								130	(8	)	138
Cooling (549 Normal)								540	(195	)	735

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

Our electric utility operating revenues increased by $9.8 million, or 1.1%, when compared to the third quarter of 2012. The most significant factors that caused a change in revenues were:

•

Wisconsin net retail pricing increases of $31.8 million ($48.7 million less $16.9 million related to Section 1603 bill credits), which is primarily related to our 2013 Wisconsin Rate Case. For information on the Section 1603 bill credits and the rate order in the 2013 rate case, see Results of Operations -- Three Months Ended September 30, 2013 -- Section 1603 Renewable Energy Treasury Grant and Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters, respectively.


•	A return to more normal weather in the third quarter of 2013 as compared to the same period in 2012 that decreased electric revenues by an estimated $31.9 million.


•	A $27.6 million increase in sales for resale due to increased sales into the MISO Energy Markets as a result of increased availability of our generating units.


•	A $7.4 million decrease in wholesale revenues in the third quarter of 2013 primarily due to reduced demand revenue as compared to the same period in 2012.


•	A $6.2 million decrease in other operating revenues, primarily driven by the amortization of $8.0 million in 2012 related to the settlement with the DOE. See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- 2012 Fuel Recovery Request.

As measured by cooling degree days, the third quarter of 2013 was 26.5% cooler than the same period in 2012 and 1.6% cooler than normal. We believe the cooler weather was the primary reason for the 8.9% decrease in residential sales. Sales to large commercial/industrial customers decreased by 6.4%, primarily because of a decrease in sales to the two iron ore mines in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased 3.5%.



September 2013	21	Wisconsin Electric Power Company

Form 10-Q

The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers have switched to an alternative electric supplier. See Factors Affecting Results, Liquidity and Capital Resources - Electric Transmission and Energy Markets - Restructuring in Michigan, for a discussion of the impact of industry restructuring in Michigan on our electric sales.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $2.7 million, or 0.8%, when compared to the third quarter of 2012. This increase was primarily caused by a 4.5% increase in total MWh sales, partially offset by lower costs as compared to the third quarter of 2012.

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 2013 with the third quarter of 2012. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues increased by $2.6 million, or 5.7%, and cost of gas sold increased by $2.4 million, or 10.9%, due to an increase in the commodity cost of natural gas.



	Three Months Ended September 30
	2013		B (W)			2012
	(Millions of Dollars)

Gas Operating Revenues	$	48.0	$	2.6		$	45.4
Cost of Gas Sold	24.4		(2.4		)	22.0
Gross Margin	$	23.6	$	0.2		$	23.4

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2013 with the third quarter of 2012:



	Three Months Ended September 30
	Gross Margin							Therm Deliveries
Gas Utility Operations	2013		B (W)			2012		2013	B (W)		2012
	(Millions of Dollars)							(Millions)
Customer Class
Residential	$	16.0	$	0.5		$	15.5	20.5	0.7		19.8
Commercial/Industrial	3.8		(0.1		)	3.9		14.0	0.4		13.6
Interruptible	0.1		0.1			—		0.5	(0.3	)	0.8
Total Retail	19.9		0.5			19.4		35.0	0.8		34.2
Transported Gas	3.5		(0.3		)	3.8		70.1	(17.1	)	87.2
Other	0.2		—			0.2		—	—		—
Total	$	23.6	$	0.2		$	23.4	105.1	(16.3	)	121.4

Weather -- Degree Days (a)
Heating (124 Normal)								130	(8	)	138

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

Our gas margin is seasonal and is primarily driven by the heating needs of our customers. The third quarter gas margin is historically the lowest of the year because of the lack of heating load. Our gas margin increased by $0.2 million, or approximately 0.9%, when compared to the third quarter of 2012.



September 2013	22	Wisconsin Electric Power Company

Form 10-Q

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $32.3 million, or approximately 10.6%, when compared to the third quarter of 2012. This increase was primarily driven by the reinstatement of $37.0 million of regulatory amortizations, offset in part by continued cost control efforts.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $4.5 million, or approximately 6.9%, when compared to the third quarter of 2012, primarily because of an overall increase in utility plant in service. The emission control equipment for units 7 and 8 of the Oak Creek Air Quality Control System (AQCS) project went into service in September 2012. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

Section 1603 Renewable Energy Treasury Grant

We expect to receive a treasury grant of approximately $72 million related to the construction of our biomass facility in Rothschild, Wisconsin. The PSCW took this grant into consideration when it set rates for our electric customers for the two years ending December 31, 2014. These rates became effective on January 1, 2013 and are reflected in the form of bill credits that reduce our revenues. We expect to recognize the treasury grant as income in the fourth quarter of 2013 when the plant is expected to be placed into service. At that time, we will also defer as a regulatory liability, the portion of the grant income that will be used to reduce rates in 2014. For the first three quarters of 2013, we experienced a mismatch between bill credits (lower revenues) and grant income. However, when the plant is placed into service in the fourth quarter, we will make an entry to record grant income to match the bill credits that have been provided to customers during 2013.

In addition, the PSCW approved escrow accounting treatment for the treasury grant. As a result, we expect to true-up any difference between the actual grant proceeds we receive and the estimated grant proceeds the PSCW used to set electric retail rates for 2013 and 2014.

Other Income, net



	Three Months Ended September 30
Other Income, net	2013			B (W)			2012
	(Millions of Dollars)

AFUDC - Equity	$	5.0		$	(3.8	)	$	8.8
Other	(0.4		)	(0.4		)	—
Other Income, net	$	4.6		$	(4.2	)	$	8.8

Other income, net decreased by $4.2 million, or approximately 47.7%, when compared to the third quarter of 2012. The decrease in AFUDC - Equity is primarily related to units 7 and 8 of the Oak Creek AQCS project going into service in September 2012.

Interest Expense, net



	Three Months Ended September 30
Interest Expense	2013		B (W)			2012
	(Millions of Dollars)

Gross Interest Costs	$	31.3	$	(0.1	)	$	31.2
Less: Capitalized Interest	2.0		(1.7		)	3.7
Interest Expense, net	$	29.3	$	(1.8	)	$	27.5



September 2013	23	Wisconsin Electric Power Company

Form 10-Q

Our gross interest costs increased by $0.1 million, or approximately 0.3%, when compared to the third quarter of 2012. Our capitalized interest decreased by $1.7 million primarily because of lower construction work in progress. As a result, our net interest expense increased by $1.8 million, or 6.5%, as compared to the third quarter of 2012.

Income Tax Expense

For the third quarter of 2013, our effective tax rate was 36.0% compared to 35.4% for the third quarter of 2012. This increase in our effective tax rate was due to reduced domestic production activities deductions and AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2012 Annual Report on Form 10-K.

RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2013

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the first nine months of 2013 with the first nine months of 2012, including favorable (better (B)) or unfavorable (worse (W)) variances:



	Nine Months Ended September 30
	Electric Revenues							MWh Sales
Electric Utility Operations	2013		B (W)			2012		2013	B (W)		2012
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	913.1	$	21.4		$	891.7	6,103.6	(250.4	)	6,354.0
Small Commercial/Industrial	798.0		18.9			779.1		6,700.1	(77.2	)	6,777.3
Large Commercial/Industrial	566.4		(2.6		)	569.0		6,885.6	(454.1	)	7,339.7
Other - Retail	17.0		0.4			16.6		109.6	(1.6	)	111.2
Total Retail	2,294.5		38.1			2,256.4		19,798.9	(783.3	)	20,582.2
Wholesale - Other	109.3		(3.0		)	112.3		1,444.7	331.6		1,113.1
Resale - Utilities	91.5		48.3			43.2		2,880.9	1,488.8		1,392.1
Other Operating Revenues	21.2		(18.0		)	39.2		—	—		—
Total	$	2,516.5	$	65.4		$	2,451.1	24,124.5	1,037.1		23,087.4

Weather -- Degree Days (a)
Heating (4,316 Normal)								4,630	1,117		3,513
Cooling (720 Normal)								678	(363	)	1,041

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

Our electric utility operating revenues increased by $65.4 million, or 2.7%, when compared to the first nine months of 2012. The most significant factors that caused a change in revenues were:


•	Wisconsin net retail pricing increases of $87.9 million ($134.8 million less $46.9 million related to Section 1603 bill credits), which is primarily related to our 2013 Wisconsin Rate Case.


•	A $48.3 million increase in sales for resale due to increased sales into the MISO Energy Markets as a result of increased availability of our generating units.


•	A return to more normal weather as compared to the prior year that decreased electric revenues by an estimated $38.4 million.


•	A $18.0 million decrease in other operating revenues, primarily driven by the amortization of $21.8 million in 2012 related to the settlement with the DOE.

As measured by cooling degree days, the first nine months of 2013 were 34.9% cooler than the same period in 2012 and 5.8% cooler than normal. Residential sales decreased by 3.9%, primarily because of weather. Sales to large commercial/industrial customers decreased by 6.2%, primarily because of a decrease in sales to the two iron ore mines in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased



September 2013	24	Wisconsin Electric Power Company

Form 10-Q

3.7%. Wholesale - Other sales increased by 29.8% primarily due to increased off-peak energy sales which generate lower incremental revenue because the majority of our wholesale revenue is tied to demand.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $37.3 million, or 4.4%, when compared to the first nine months of 2012. This increase was primarily caused by a 4.5% increase in total MWh sales.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first nine months of 2013 with the first nine months of 2012. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues increased by $41.3 million, or 15.7%, and cost of gas sold increased by $30.0 million, or 19.5%, due to cooler weather and an increase in the commodity cost of natural gas.



	Nine Months Ended September 30
	2013		B (W)			2012
	(Millions of Dollars)

Gas Operating Revenues	$	304.6	$	41.3		$	263.3
Cost of Gas Sold	184.1		(30.0		)	154.1
Gross Margin	$	120.5	$	11.3		$	109.2

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2013 with the first nine months of 2012:



	Nine Months Ended September 30
	Gross Margin							Therm Deliveries
Gas Utility Operations	2013		B (W)			2012		2013	B (W)		2012
	(Millions of Dollars)							(Millions)
Customer Class
Residential	$	81.5	$	8.0		$	73.5	248.3	57.5		190.8
Commercial/Industrial	25.6		3.3			22.3		140.2	32.1		108.1
Interruptible	0.4		0.1			0.3		3.8	0.4		3.4
Total Retail	107.5		11.4			96.1		392.3	90.0		302.3
Transported Gas	11.9		(0.2		)	12.1		233.4	(28.2	)	261.6
Other	1.1		0.1			1.0		—	—		—
Total	$	120.5	$	11.3		$	109.2	625.7	61.8		563.9

Weather -- Degree Days (a)
Heating (4,316 Normal)								4,630	1,117		3,513

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

Our gas margin increased by $11.3 million, or approximately 10.3%, when compared to the first nine months of 2012. This increase primarily relates to an increase in sales volumes as a result of cooler weather during the first nine months of 2013 that increased heating loads. We estimate that weather increased gas margins by approximately $15.5 million. As measured by heating degree days, the first nine months of 2013 were 31.8% cooler than the same period in 2012 and 7.3% cooler than normal. Gas margins were reduced by approximately $5.2



September 2013	25	Wisconsin Electric Power Company

Form 10-Q

million because of lower gas rates that became effective January 1, 2013. For information on this rate order, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $63.4 million, or approximately 6.6%, when compared to the first nine months of 2012. This increase was primarily driven by the reinstatement of $111.0 million of regulatory amortizations, offset in part by continued cost control efforts across the utility.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $17.4 million, or approximately 9.2%, when compared to the first nine months of 2012, primarily because of an overall increase in utility plant in service. The emission control equipment for units 5 and 6 of the Oak Creek AQCS project went into service in March 2012, and for units 7 and 8 in September 2012.

Section 1603 Renewable Energy Treasury Grant

For a discussion of the impact of the Section 1603 renewable energy treasury grant on our results of operations, see Results of Operations -- Three Months Ended September 30, 2013 -- Section 1603 Renewable Energy Treasury Grant.

Other Income, net



	Nine Months Ended September 30
Other Income, net	2013		B (W)			2012
	(Millions of Dollars)

AFUDC - Equity	$	13.7	$	(17.7	)	$	31.4
Other	0.4		(0.9		)	1.3
Other Income, net	$	14.1	$	(18.6	)	$	32.7

Other income, net decreased by $18.6 million, or approximately 56.9%, when compared to the first nine months of 2012. The decrease in AFUDC - Equity is primarily related to the Oak Creek AQCS project which emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8.

Interest Expense, net



	Nine Months Ended September 30
Interest Expense	2013		B (W)			2012
	(Millions of Dollars)

Gross Interest Costs	$	97.2	$	(3.4	)	$	93.8
Less: Capitalized Interest	5.7		(7.4		)	13.1
Interest Expense, net	$	91.5	$	(10.8	)	$	80.7

Our gross interest costs increased by $3.4 million, or approximately 3.6%, when compared to the first nine months of 2012 primarily because we issued $250 million of long-term debt in December 2012. Our capitalized interest decreased by $7.4 million primarily because of lower construction work in progress. As a result, our net interest expense increased by $10.8 million, or 13.4%, as compared to the first nine months of 2012.

Income Tax Expense

For the first nine months of 2013, our effective tax rate was 35.5% compared to 34.7% for the first nine months of 2012. This increase in our effective tax rate was due to reduced domestic production activities deductions and



September 2013	26	Wisconsin Electric Power Company

Form 10-Q

AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2012 Annual Report on Form 10-K. We expect our 2013 annual effective tax rate to be between 35% and 36%.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following summarizes our cash flows during the nine months ended September 30:



	2013			2012
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	739.3		$	644.4
Investing Activities	$	(405.6	)	$	(404.0	)
Financing Activities	$	(350.7	)	$	(241.0	)

Operating Activities

Cash provided by operating activities increased by $94.9 million during the first nine months of 2013 as compared to the same period in 2012. The increase is primarily because of lower contributions to our benefit plans. During the first nine months of 2013, we made no contributions to our benefit plans, compared to contributions of $92.9 million during the first nine months of 2012. In addition, we had higher depreciation expense and higher amortization expense. Included in the higher amortization expense is a $94.9 million increase in the amortization of regulatory items. Partially offsetting these items are lower net income and higher working capital requirements.

Investing Activities

Cash used in investing activities increased by $1.6 million during the first nine months of 2013 as compared to the same period in 2012. Our change in restricted cash decreased by $33.3 million which is related to the 2012 release of restricted cash through bill credits and reimbursements of costs associated with the DOE settlement. Our capital expenditures decreased by $21.9 million during the first nine months of 2013 as compared to the same period in 2012, primarily because of the completion of the Oak Creek AQCS project during the third quarter of 2012.

Financing Activities

Cash used in financing activities increased by $109.7 million during the first nine months of 2013 as compared to the same period in 2012. During the first nine months of 2013, we retired $300.0 million of long-term debt and issued $250 million of long-term debt. The net proceeds of the debt issuance were used to repay short-term debt and for other corporate purposes. In addition, we paid $95.3 million more dividends to Wisconsin Energy during the first nine months of 2013 as compared to the same period in 2012 which includes a special $50 million dividend to balance our capital structure.

CAPITAL RESOURCES AND REQUIREMENTS

Working Capital

As of September 30, 2013, our current liabilities exceeded our current assets by approximately $12.2 million. We do not expect this to have any impact on our liquidity because we believe we have adequate back-up lines of credit in place for on-going operations. We also have access to the capital markets to finance our construction program and to refinance current maturities of long-term debt if necessary.



September 2013	27	Wisconsin Electric Power Company

Form 10-Q

Liquidity

We anticipate meeting our capital requirements during the remainder of 2013 and beyond primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors, and equity contributions from our parent.

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

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

As of September 30, 2013, we had approximately $493.9 million of available, undrawn lines under our bank back-up credit facility, and approximately $26.5 million of commercial paper outstanding that was supported by the available lines of credit. During the first nine months of 2013, our maximum commercial paper outstanding was $354.5 million with a weighted-average interest rate of 0.22%.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facility as of September 30, 2013:



Total Facility		Letters of Credit		Credit Available		Facility Expiration
(Millions of Dollars)

$	500.0	$	6.1	$	493.9	December 2017

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of September 30, 2013, the repurchased bonds were still outstanding, but were not reported as long-term debt because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Bonus Depreciation Provisions

The American Taxpayer Relief Act of 2012 was signed into law on January 2, 2013, which extended the 50% bonus depreciation rules to include assets placed in service in 2013. These rules will apply to the biomass plant we are constructing in Rothschild, which is expected to be completed during the fourth quarter of 2013. As a result of the increased federal tax depreciation for 2013 and prior years, we do not anticipate making federal income tax payments for 2013.

Credit Rating Risk

Access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, security ratings reflect the views of the rating agencies only. An explanation of the significance of the ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

See Capital Resources and Requirements -- Credit Rating Risk in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2012 Annual Report on Form 10-K for additional information related to our credit rating risk.



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Form 10-Q

Capital Requirements

Capital Expenditures: Capital requirements during the remainder of 2013 are expected to be principally for capital expenditures relating to our electric and gas distribution systems and our biomass facility. We estimate that we will spend approximately $520 million on capital expenditures during 2013.

Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 9 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements in this report.

Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments were approximately $27.4 billion as of September 30, 2013 compared with $27.9 billion as of December 31, 2012.

FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity and capital resources. The following discussion should be read together with the information under the heading "Factors Affecting Results, Liquidity and Capital Resources" in Item 7 of our 2012 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, Wisconsin Energy's PTF strategy, rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring and competition and other matters.

POWER THE FUTURE

All of the PTF units are in service and are positioned to provide a significant portion of our future generation needs. We are leasing the units from We Power under long-term leases. We are recovering the lease payments associated with Port Washington Generating Station Unit 1, Port Washington Generating Station Unit 2, Oak Creek expansion Unit 1, and Oak Creek expansion Unit 2 in our rates as authorized by the PSCW, the Michigan Public Service Commission (MPSC) and FERC.

As part of our 2013 Wisconsin Rate Case, the PSCW determined that 100% of the construction costs for the Oak Creek expansion units were prudently incurred by We Power, and approved the recovery in rates of more than 99.5% of these costs. In addition, the PSCW deferred the final decision regarding $24 million related to the Oak Creek expansion fuel flexibility project until a future rate proceeding. See Other Matters below for additional information about the fuel flexibility project.

We Power assigned its warranty rights to us upon turnover of each of the Oak Creek expansion units. The warranty claim for costs incurred to repair steam turbine corrosion damage identified on both units was scheduled to go to arbitration in October 2013, but we entered into a settlement agreement with Bechtel Power Corporation (Bechtel) on June 21, 2013 resolving the claim, as well as several other warranty claims. This settlement did not have a material impact to our financial statements. We, along with Bechtel, continue to work through two remaining items.

Pursuant to the terms of this settlement agreement, Bechtel achieved final acceptance of both Oak Creek expansion units. In turn, We Power paid $5.0 million to Bechtel, which represents the amount agreed to as part of the December 2009 settlement and release agreement for achieving final acceptance.

See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2012 Annual Report on Form 10-K for additional information on PTF.



September 2013	29	Wisconsin Electric Power Company

Form 10-Q

RATES AND REGULATORY MATTERS

2013 Wisconsin Rate Case: On March 23, 2012, we initiated rate proceedings with the PSCW. On December 20, 2012, the PSCW approved the following rate adjustments:

•

A net bill increase related to non-fuel costs for our Wisconsin retail electric customers of approximately $70 million (2.6%) for 2013. This amount reflects an offset of approximately $63 million (2.3%) related to the proceeds of the Section 1603 renewable energy cash grant we expect to receive upon completion of our biomass facility currently under construction. Absent this offset, the retail electric rate increase for non-fuel costs is approximately $133 million (4.8%) for 2013.


•	Absent an adjustment for any remaining energy cash credits, an electric rate increase for our Wisconsin electric customers of approximately $28 million (1.0%) for 2014.


•	Recovery of a forecasted increase in fuel costs of approximately $44 million (1.6%) for 2013.


•	A rate decrease of approximately $8 million (1.9%) for our natural gas customers for 2013, with no rate adjustment in 2014. The new rates reflect a $6.4 million reduction in bad debt expense.


•	An increase of approximately $1.3 million (6.0%) for our Downtown Milwaukee (Valley) steam utility customers for 2013 and another $1.3 million (6.0%) in 2014.


•	An increase of approximately $1 million (7.0%) in 2013 and $1 million (6.0%) in 2014 for our Milwaukee County steam utility customers.

These rate adjustments were effective January 1, 2013. In addition, the PSCW indicated that our allowed return on equity would remain at 10.4%. The PSCW also approved escrow accounting treatment for the energy cash grant.

2014 Fuel Recovery Request: On July 30, 2013, we filed our 2014 fuel plan with the PSCW requesting authority to refund Wisconsin retail electric customers approximately $30 million in the form of a fuel credit related to a reduction in delivered coal costs. We anticipate an order from the PSCW by the end of the year.

2012 Fuel Recovery Request: In August 2011, we filed a $50 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The primary reasons for the increase were projected higher coal, coal transportation and purchased power costs. In January 2012, the PSCW issued an order which provided for an increase in fuel costs of approximately $26 million, offset by approximately $26 million from the settlement with the DOE regarding the storage of spent nuclear fuel, resulting in no change in customer bills. In March of this year, we filed our annual fuel reconciliation for the 2012 fuel recovery request. The reconciliation was approved by the PSCW and we received the written order on July 31, 2013.

Renewable Energy Portfolio: We are constructing a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site. Wood waste and wood shavings will be used to produce approximately 50 MW of renewable electricity and will also support Domtar's sustainable papermaking operations. Construction commenced in June 2011. We currently expect to invest $269.5 million, excluding AFUDC, in the plant. We are targeting completion of the facility by the end of 2013.

Oak Creek Air Quality Control System: In July 2008, we received approval from the PSCW to construct wet flue gas desulfurization and selective catalytic reduction facilities at Oak Creek Power Plant units 5-8. Construction of these emission controls began in late July 2008. In March 2012, the wet flue gas desulfurization and selective catalytic reduction equipment for units 5 and 6 was placed into commercial operation. In September 2012, the equipment for units 7 and 8 was placed into commercial operation. The final cost of completing this project was approximately $740 million ($900 million including AFUDC). The cost of constructing these facilities has been included in our previous estimates of the costs to implement the Consent Decree we entered into with the United States Environmental Protection Agency (EPA) in 2003.

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 of our 2012 Annual Report on Form 10-K for additional information regarding our rates and other regulatory matters.

ELECTRIC TRANSMISSION AND ENERGY MARKETS

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the Locational Marginal Price (LMP) system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through Auction Revenue Rights



September 2013	30	Wisconsin Electric Power Company

Form 10-Q

(ARRs) and FTRs. ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2013 through May 31, 2014. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

Restructuring in Michigan: Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. The two iron ore mines are excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

The mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers have switched to an alternative electric supplier. Sales to these customers, including the mines, totaled 2,173.6 GWh, or 7.6% of our retail electric sales for the year ended December 31, 2012. We do not expect the loss of the mines or the other customers to have a material impact on our consolidated results of operations in 2013. Previously, the owner of the mines announced that they would shut down the Empire mine by the end of 2014 or beginning of 2015.

Before implementation of steps to mitigate the loss of these sales, we estimate that the impact of these losses in 2014 would be approximately $50 million to $54 million before income taxes. We have taken, and will continue to take, multiple steps to mitigate these losses for 2014 and going forward.

We filed a request with MISO to suspend the operation of all five units at Presque Isle Power Plant (PIPP). On October 16, 2013, MISO informed us that the operation of all units is necessary to maintain reliability in the Upper Peninsula of Michigan. As a result, we are eligible for system support resource (SSR) payments from MISO to recover costs for operating the units, and we will be working with MISO to determine the amount of the SSR payments. We expect to become eligible to receive SSR payments in February of 2014. Depending on the level of operating and maintenance expenses included in these payments and the degree to which costs for new capital investments and carrying costs for previous capital investments are reflected, these payments could range from $35 million to $82 million on an annualized basis.

We filed an application with the MPSC requesting authority to defer all fixed production costs that would have been recovered from the customers who switched to an alternative electric supplier. In August 2013, the MPSC issued an order approving the deferral of costs allocable to our remaining Michigan retail customers. On September 30, 2013, we filed a petition for re-hearing with the MPSC requesting reconsideration of its deferral order. Our ability to collect the deferred costs will be determined in a subsequent rate proceeding.

We file bi-annual retail rate cases in Wisconsin. Our next electric rate case in Wisconsin is for rates to be implemented in January 2015. Wholesale electric rates are set under FERC formula cost-based rates and are adjusted annually. We believe that prudently incurred utility costs will be recovered in future Wisconsin retail rate cases and FERC filings.

Although the financial impact in future periods is uncertain, we expect that our net financial exposure will be immaterial if the mitigation efforts outlined above are successful.

ENVIRONMENTAL MATTERS

Air Quality

Sulfur Dioxide Standard: In June 2010, the EPA issued a new 1 hour Sulfur Dioxide (SO₂) National Ambient Air Quality Standard that became effective in August 2010. This standard represented a significant change from the previous SO₂ standard. The implementation guidance for the new standard, among other things, required attainment designations to be based on modeling rather than monitoring. Traditionally, attainment designations were based on monitored data. The EPA has since advised that, based on stakeholder input, it is revisiting this implementation guidance. The EPA has issued two technical assistance documents for comment in 2013 and expects to issue a rule in 2014 that will establish requirements for characterizing SO₂air quality in priority areas.

Various parties have submitted judicial and administrative challenges to this rule, and litigation is pending in the U.S. Court of Appeals for the D.C. Circuit challenging, among other things, the stringency of the standards and the EPA's plans to require attainment designations to be based on modeling.



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Form 10-Q

If the new standard remains in place we do not believe that we will need to make any significant additional expenditure at the majority of our generating units because of prior investments in pollution control equipment. However, if the new standard does remain in place we believe that additional environmental controls will be required at PIPP located in the Upper Peninsula of Michigan. In November of 2012 we entered into a joint venture agreement with Wolverine Power Supply Cooperative, Inc. (Wolverine) whereby Wolverine would pay for the installation of the air quality control systems at PIPP and receive a minority undivided ownership interest in the plant in return.

However, in light of the recent loss of retail electric customers in Michigan due to that state’s alternative electric supplier program (see Restructuring in Michigan under Electric Transmission and Energy Markets) we are re-evaluating options related to the ownership and operation of PIPP including different alternatives for the joint venture with Wolverine. At the same time, we are analyzing several environmental compliance options at PIPP.

The new standard may also require us to make modifications at some of our smaller generation units.

Mercury and Other Hazardous Air Pollutants: In December 2011, the EPA issued the final Mercury and Air Toxics Standard (MATS) rule, which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric generating units. We currently anticipate that only PIPP will require modifications, and are currently evaluating several available options for PIPP to comply with MATS. If the joint venture with Wolverine moves forward we expect the modifications to be funded by Wolverine. In April 2013, we received a one year MATS compliance extension through April 16, 2016 from the Michigan Department of Environmental Quality (MDEQ).

Cross-State Air Pollution Rule: In August 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR), formerly known as the Clean Air Transport Rule. This rule was proposed in 2010 to replace the Clean Air Interstate Rule (CAIR), which had been remanded to the EPA in 2008. The stated purpose of the CSAPR is to limit the interstate transport of emissions of Nitrogen Oxide (NO_X) and SO₂ that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation plan. Even with technical revisions to the rule by the EPA, PIPP may not have been allocated sufficient allowances to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. This situation could then put the plant at risk for certain penalties under the rule.

The rule was scheduled to become effective January 1, 2012. However, we and a number of other parties sought judicial review of the rule, and in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CSAPR, keeping the CAIR in effect. The EPA petitioned the United States Supreme Court, who agreed to hear the case. A decision is expected in mid-2014.

Climate Change: Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas emissions. The President and his administration recently reaffirmed that regulation of greenhouse gas emissions continues to be a top priority. In June 2013, the President issued a presidential memorandum instructing the EPA to, among other things, issue rules pertaining to greenhouse gas emissions from both new and existing power plants.

The EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the Clean Air Act. On September 20, 2013, the EPA withdrew its 2012 proposed New Source Performance Standards greenhouse gas emissions rule, and issued new proposed rules with greenhouse gas limits for new fossil fueled power plants. The rule does not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines.

With respect to existing generating units, the EPA has indicated that it intends to issue a proposed rule in June 2014, a final rule by June 2015 and require State Implementation Plans to be submitted by June 30, 2016. Any such regulations may impact how we operate our existing facilities. Depending on the extent of rate recovery and other factors, these anticipated future rules could have a material adverse impact on our financial condition. For additional information, see the caption "We may face significant costs to comply with the regulation of greenhouse gas emissions." under Item 1A Risk Factors in our 2012 Annual Report on Form 10-K.

Valley Power Plant Conversion: In August 2012, we announced plans to convert the fuel source for Valley Power Plant (VAPP) from coal to natural gas. We currently expect the cost of this conversion to be between $65 million



September 2013	32	Wisconsin Electric Power Company

Form 10-Q

and $70 million excluding AFUDC, and, subject to receipt of PSCW approval and a construction air permit from the WDNR, anticipate that the conversion will be completed by the end of 2015 or early 2016. We filed for a Certificate of Authority from the PSCW on April 26, 2013. The construction air permit for the gas conversion is expected to be issued by the WDNR before the end of the year.

In June 2012, we received approval from the PSCW to replace and upgrade the Lincoln Arthur natural gas main, which has the capability to accommodate the increased natural gas required for the conversion of VAPP to natural gas. Construction began on the Lincoln Arthur natural gas main in March 2013.

Water Quality

Steam Electric Effluent Guidelines: These guidelines regulate waste water discharges from our power plant processes. In June 2013, the EPA issued a proposed rule for comment to modify these guidelines. We submitted comments primarily addressing potential effects to our wastewater treatment facilities and coal combustion residuals effluent management activities. The rules are expected to be finalized by May 2014. After promulgation of the final rules, the WDNR and MDEQ will need to modify state rules accordingly and then incorporate new requirements into our facility permits. The rule compliance deadline is as soon as possible after July 1, 2017 with full compliance expected by July 1, 2022. We already meet many of the proposed requirements defined by EPA, and as a result believe we will be well positioned to comply with the proposed guidelines. There are several available options outlined in the proposed rule. The amount of additional costs we may need to incur to comply with the new guidelines, if any, will depend on which option(s) the EPA selects to incorporate into the final guidelines. Until the rules are finalized, we are unable to determine the impact on our facilities.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2012 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

OTHER MATTERS

Oak Creek Expansion Fuel Flexibility Project: The Oak Creek expansion units were designed and permitted to use bituminous coal from the Eastern United States. Market forces have resulted in a significant price differential between bituminous and sub-bituminous coals. We received a new air construction permit from the WDNR to modify the Oak Creek expansion units for potential future use of sub-bituminous coal. In May 2013, we began testing various combinations of sub-bituminous coal and bituminous coal to identify any equipment limitations that should be considered prior to filing with the PSCW for a Certificate of Authority to make any fuel flexibility modifications. In February 2013, the Sierra Club and the Midwest Environmental Defense Center filed a petition for a contested case hearing with the WDNR to challenge the issuance of the air construction permit. The WDNR has granted that petition, but a hearing has not yet been scheduled.

Paris Generating Station Units 1 and 4 Temporary Outage: Between 2000 and 2002, we replaced the blades on the four Paris Generating Station (PSGS) combustion turbine generators with blades that were approximately 7% more efficient. Although the work was performed as routine maintenance that we did not believe required a construction permit at the time and the plant has not been operated to use the potential additional capacity, the WDNR has indicated that it now considers this maintenance to be a modification requiring a construction permit. The WDNR issued us a Notice of Violation (NOV) on January 7, 2013 alleging violations of the new source review rules and certain Wisconsin environmental rules. At the same time, the WDNR also issued an administrative order that prohibits us from operating PSGS Units 1 and 4 until the earlier of: (1) Units 1 and 4 achieve the applicable NO_x emission rates; (2) the Wisconsin regulations are revised so that Units 1 and 4 can achieve the emission limits or are no longer subject to the limits; (3) the alleged modification is resolved through a consent decree; or (4) until a court decides that the blade replacement project was not a major modification. We are presently evaluating alternative approaches to return these peaking units to service, and expect that Units 1 and 4 will remain out of service until at least 2014. In addition, we may be subject to fines and penalties. In February 2013, the Sierra Club filed for a contested case hearing with the WDNR in connection with the administrative order. The WDNR has granted that petition, but a hearing has not yet been scheduled. In addition, in May 2013, the WDNR referred the matter to the Wisconsin Department of Justice (DOJ) for alleged violations of air management statutes and rules.

We evaluated the impact that this outage may have on network reliability, and concluded that we will not need to find alternative sources of generation in the short-term to replace the generation from these units during the temporary outage.



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PSGS Units 2 and 3 remain available for operation because the turbine blade maintenance on these units occurred prior to a rule change in 2001.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our Annual Report on Form 10-K for the year ended December 31, 2012. 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 2012 Annual Report on Form 10-K, as well as Note 5 -- Fair Value Measurements and Note 6 -- Derivative Instruments in the Notes to Consolidated Condensed Financial Statements in this report.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures: Our management, with the participation of our principal executive officer and principal 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 Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal 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 principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2012 Annual Report on Form 10-K.

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

ENVIRONMENTAL MATTERS

Paris Generating Station: See Factors Affecting Results, Liquidity and Capital Resources -- Other Matters for information concerning a NOV issued in connection with the replacement of certain turbine blades as part of maintenance performed on Units 1 and 4 at PSGS.

Bluff Collapse: On October 31, 2011, a portion of the bluff at our Oak Creek Power Plant collapsed. The affected area, located south of the new AQCS, was a former ravine that had been filled with coal ash prior to the advent of landfill regulations. Following the receipt of permits and approvals from the WDNR, bluff reconstruction and stabilization were completed in November 2012. We received final spill closure related to our rework of the storm water management infrastructure from the WDNR in December 2012, following submission of environmental



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studies and reports. In addition, the EPA issued its final incident situation report in November 2012. The final construction documentation report was submitted to the WDNR in December 2012.

A June 2012 letter from the WDNR alleged non-compliance with certain environmental regulations. In July 2012, the WDNR referred the matter to the DOJ. On July 8, 2013, the Racine County Circuit Court approved a stipulation and settlement agreement in State of Wisconsin v. Wisconsin Electric Power Company (Racine County Case Number 2013CX000002). As part of the settlement agreement, we paid a total of $100,000 to reimburse the state of Wisconsin for its costs in responding to the collapse and for its attorneys' fees, as well as for assessments and penalties. This settlement agreement fully resolves this matter.

In addition, in November 2011, the Sierra Club provided a Notice of Intent to file a citizens suit under the Clean Water Act and Resource Conservation and Recovery Act for alleged violations related to this incident. We have responded that we do not believe there is any basis for a citizen suit. To date, the Sierra Club has not filed suit.

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.

ITEM 1A. RISK FACTORS

Other than as set forth below, there have been no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2012. See Item 1A. Risk Factors in our 2012 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

Restructuring in the regulated energy industry could have a negative impact on our business.

The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us. It is uncertain whether retail access might be implemented in Wisconsin.

Michigan has adopted retail choice. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. The two iron ore mines are excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

The mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers have switched to an alternative electric supplier. Sales to these customers, including the mines, totaled 2,173.6 GWh, or 7.6% of our retail electric sales for the year ended December 31, 2012. Previously, the owner of the mines announced that they would shut down the Empire mine by the end of 2014 or beginning of 2015. Before implementation of steps to mitigate the loss of these sales, we estimate that the impact of these losses in 2014 would be approximately $50 million to $54 million before income taxes.

FERC continues to support the existing Regional Transmission Organizations (RTO) that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. The MISO Energy Markets rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes a LMP that reflects the market price for energy. As a participant in the MISO Energy Markets, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system. MISO also implemented an Ancillary Services Market for operating reserves that was simultaneously co-optimized with its existing energy markets.



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These market designs have the potential to increase the costs of transmission, the costs associated with inefficient generation dispatching, the costs of participation in the market and the costs associated with estimated payment settlements.

ITEM 6. EXHIBITS



Exhibit No.

10		Material Contracts

10.1		First Amendment to Restated Rabbi Trust Agreement (the Non-Qualified Trust Agreement) by and between Wisconsin Energy Corporation and The Northern Trust Company, effective as of July 23, 2013. (Exhibit 10.1 to Wisconsin Energy Corporation’s 09/30/2013 Form 10-Q (File No. 001-09057).)

12		Statements re Computation of Ratios

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges.

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

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

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

32		Section 1350 Certifications

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

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

101		Interactive Data File



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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		WISCONSIN ELECTRIC POWER COMPANY
		(Registrant)

		/s/STEPHEN P. DICKSON
Date:	November 1, 2013	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer



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