WISCONSIN ELECTRIC POWER CO - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - WISCONSIN ELECTRIC POWER CO	Financial_Report.xls
EX-31.1 - WISCONSIN ELECTRIC EXHIBIT 31.1 - WISCONSIN ELECTRIC POWER CO	wepco09302014ex311.htm
EX-31.2 - WISCONSIN ELECTRIC EXHIBIT 31.2 - WISCONSIN ELECTRIC POWER CO	wepco09302014ex312.htm
EX-32.1 - WISCONSIN ELECTRIC EXHIBIT 32.1 - WISCONSIN ELECTRIC POWER CO	wepco09302014ex321.htm
EX-32.2 - WISCONSIN ELECTRIC EXHIBIT 32.2 - WISCONSIN ELECTRIC POWER CO	wepco09302014ex322.htm

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, 2014



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, 2014):



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, 2014



	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	35

	Part II -- Other Information

1.	Legal Proceedings	35

1A.	Risk Factors	35

6.	Exhibits	37

	Signatures	38



September 2014	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
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
BART		Best Available Retrofit Technology
BTA		Best Technology Available
CAIR		Clean Air Interstate Rule
CSAPR		Cross-State Air Pollution Rule
EM		Entrainment Mortality
GHG		Greenhouse Gas
IM		Impingement Mortality
MATS		Mercury and Air Toxics Standards
NAAQS		National Ambient Air Quality Standards
NOV		Notice of Violation
NO_x		Nitrogen Oxide
PSD		Prevention of Significant Deterioration
SIP		State Implementation Plan
SO₂		Sulfur Dioxide

Other Terms and Abbreviations
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



September 2014	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:

HSR Act		Hart-Scott-Rodino Antitrust Improvements Act of 1976
Integrys		Integrys Energy Group, Inc.
LMP		Locational Marginal Price
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Market
OTC		Over-the-Counter
PTF		Power the Future
SSR		System Support Resource
Treasury Grant		Section 1603 Renewable Energy Treasury Grant

Measurements
Btu		British Thermal Unit(s)
Dth		Dekatherm(s) (One Dth equals one million Btu)
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
OPEB		Other Post-Retirement Employee Benefits



September 2014	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, retail sales and customer growth, rate actions and related filings with the appropriate regulatory authorities, current and proposed environmental regulations and other regulatory matters and related estimated expenditures, on-going legal proceedings, projections related to the pension and other post-retirement benefit plans, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, 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," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will" 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 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 rate cases and negotiations.


•	The impact across our service territories of the continued adoption of distributed generation by our electric customers, and our ability to design and implement an appropriate rate structure to mitigate these impacts.


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


•	Our ability to continue 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 electric generation facilities, as well as upgrades to our generation fleet and 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; regulatory initiatives regarding deregulation and restructuring of the electric and/or gas utility industry; 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 cyber security threats; the regulatory approval process for new generation and transmission



September 2014	5	Wisconsin Electric Power Company

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

facilities and new pipeline construction; adoption of new, or changes in existing, environmental, federal and state energy, tax and other laws and regulations to which we may become, or are, subject; changes in allocation of energy assistance, including state public benefits funds; changes in the application or enforcement 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.


•	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, as well as the ability of ATC and the Duke-American Transmission Company to obtain the required approvals for their transmission projects.


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


•	Advances in technology 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.


•	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, 2013 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 2014	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 1,130,600 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 472,600 gas customers in Wisconsin and approximately 440 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 9 --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 owns and leases to us the generating capacity included in Wisconsin Energy's Power the Future (PTF) strategy, which is described further in this report and in our 2013 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, 2014, Bostco had $28.6 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 Generally Accepted Accounting Principles pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2013 Annual Report on Form 10-K, including the financial statements and notes therein.



September 2014	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
	2014		2013		2014		2013
	(Millions of Dollars)

Operating Revenues	$	937.8	$	964.6	$	3,070.2	$	2,849.7

Operating Expenses
Fuel and purchased power	338.2		340.4		951.8		890.1
Cost of gas sold	27.7		24.4		327.8		184.1
Other operation and maintenance	315.8		338.0		972.2		1,023.1
Depreciation and amortization	74.9		69.5		220.9		207.4
Property and revenue taxes	28.5		27.7		85.4		83.1
Total Operating Expenses	785.1		800.0		2,558.1		2,387.8

Treasury Grant	3.5		—		10.1		—

Operating Income	156.2		164.6		522.2		461.9

Equity in Earnings of Transmission Affiliate	15.9		15.1		46.4		44.9
Other Income, net	1.4		4.6		8.0		14.1
Interest Expense, net	29.0		29.3		87.6		91.5

Income Before Income Taxes	144.5		155.0		489.0		429.4

Income Tax Expense	54.4		55.8		181.3		152.4

Net Income	90.1		99.2		307.7		277.0

Preferred Stock Dividend Requirement	0.3		0.3		0.9		0.9

Earnings Available for Common Stockholder	$	89.8	$	98.9	$	306.8	$	276.1

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



September 2014	8	Wisconsin Electric Power Company

Form 10-Q



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
	September 30, 2014			December 31, 2013
	(Millions of Dollars)
Assets
Property, Plant and Equipment
In service	$	10,424.3		$	10,160.6
Accumulated depreciation	(3,386.5		)	(3,258.8		)
	7,037.8			6,901.8
Construction work in progress	148.0			101.9
Leased facilities, net	2,224.8			2,279.0
Net Property, Plant and Equipment	9,410.6			9,282.7
Investments
Equity investment in transmission affiliate	372.1			354.1
Other	0.3			0.2
Total Investments	372.4			354.3
Current Assets
Cash and cash equivalents	15.4			25.1
Accounts receivable, net	277.5			335.7
Accounts receivable from related parties	22.0			9.1
Accrued revenues	144.9			240.7
Materials, supplies and inventories	281.0			281.0
Current deferred tax asset, net	1.4			75.8
Prepayments and other	119.9			146.4
Total Current Assets	862.1			1,113.8
Deferred Charges and Other Assets
Regulatory assets	1,446.7			1,370.3
Other	155.7			164.5
Total Deferred Charges and Other Assets	1,602.4			1,534.8
Total Assets	$	12,247.5		$	12,285.6
Capitalization and Liabilities
Capitalization
Common equity	$	3,395.7		$	3,406.8
Preferred stock	30.4			30.4
Long-term debt	2,415.0			2,167.3
Capital lease obligations	2,706.8			2,712.0
Total Capitalization	8,547.9			8,316.5
Current Liabilities
Long-term debt and capital lease obligations due currently	98.5			379.5
Short-term debt	170.7			174.5
Subsidiary note payable to Wisconsin Energy	22.7			22.8
Accounts payable	249.7			273.8
Accounts payable to related parties	102.9			85.9
Accrued payroll and benefits	65.5			89.3
Other	156.6			132.3
Total Current Liabilities	866.6			1,158.1
Deferred Credits and Other Liabilities
Regulatory liabilities	621.1			634.2
Deferred income taxes - long-term	1,846.6			1,794.5
Pension and other benefit obligations	160.5			160.1
Other	204.8			222.2
Total Deferred Credits and Other Liabilities	2,833.0			2,811.0
Total Capitalization and Liabilities	$	12,247.5		$	12,285.6

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



September 2014	9	Wisconsin Electric Power Company

Form 10-Q



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

	Nine Months Ended September 30
	2014			2013
	(Millions of Dollars)
Operating Activities
Net income	$	307.7		$	277.0
Reconciliation to cash
Depreciation and amortization	226.2			214.1
Deferred income taxes and investment tax credits, net	125.6			145.5
Change in - Accounts receivable and accrued revenues	136.0			17.0
Inventories	—			13.2
Other current assets	36.0			36.9
Accounts payable	(7.4		)	(49.3		)
Accrued income taxes, net	28.8			24.4
Other current liabilities	(24.1		)	17.1
Other, net	(60.8		)	43.4
Cash Provided by Operating Activities	768.0			739.3

Investing Activities
Capital expenditures	(377.7		)	(363.6		)
Cost of removal, net of salvage	(15.6		)	(24.2		)
Investment in transmission affiliate	(9.2		)	(6.9		)
Other, net	3.1			(10.9		)
Cash Used in Investing Activities	(399.4		)	(405.6		)

Financing Activities
Dividends paid on common stock	(330.0		)	(230.0		)
Dividends paid on preferred stock	(0.9		)	(0.9		)
Issuance of long-term debt	250.0			250.0
Retirement of long-term debt	(300.0		)	(300.0		)
Change in total short-term debt	(3.9		)	(79.6		)
Other, net	6.5			9.8
Cash Used in Financing Activities	(378.3		)	(350.7		)

Change in Cash and Cash Equivalents	(9.7		)	(17.0		)

Cash and Cash Equivalents at Beginning of Period	25.1			34.1

Cash and Cash Equivalents at End of Period	$	15.4		$	17.1

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



September 2014	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 2013 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, 2014 are not necessarily indicative of the results which may be expected for the entire fiscal year 2014 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition: In May 2014, the Financial Accounting Standards Board and the International Accounting Standards Board issued their joint revenue recognition standard Accounting Standards Update 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2016, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our consolidated financial statements.

3 -- PROPOSED ACQUISITION OF INTEGRYS BY PARENT COMPANY

On June 22, 2014, our parent company, Wisconsin Energy, entered into an agreement and plan of merger under which it will acquire Integrys Energy Group (Integrys). Integrys' shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash per Integrys share of common stock, with the total consideration valued at approximately $5.4 billion, based upon the value of Wisconsin Energy's common stock as of September 30, 2014. The cash consideration will be financed through the issuance of approximately $1.5 billion of debt at the holding company level.

The acquisition is subject to several conditions, including, among others, approval of the shareholders of both Wisconsin Energy and Integrys, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), and the receipt of approvals from various government agencies, including the Federal Energy Regulatory Commission (FERC), Federal Communications Commission, Public Service Commission of Wisconsin (PSCW), Illinois Commerce Commission, Michigan Public Service Commission (MPSC) and Minnesota Public Utilities Commission. The status of these matters is as follows:


•	On August 6, 2014, Wisconsin Energy filed applications for approval with the PSCW, Illinois Commerce Commission, MPSC and Minnesota Public Utilities Commission.

•

On August 13, 2014, Wisconsin Energy filed an initial registration statement on Form S-4 with the SEC to register the stock consideration. On October 6, 2014, the Form S-4, which contains a joint proxy statement/prospectus for Wisconsin Energy and Integrys, was declared effective by the SEC. Meetings for Wisconsin Energy and Integrys shareholders to vote on the acquisition are scheduled for November 21, 2014.


•	On August 15, 2014, Wisconsin Energy filed an application with the FERC.


•	On September 24, 2014, Wisconsin Energy submitted its HSR Act filings, and on October 24, 2014, the United States Department of Justice closed its review of the transaction with no further action required. In addition, on October 24, 2014, the Federal Trade Commission granted early termination of the 30-day waiting period required by the HSR Act.

Wisconsin Energy anticipates the transaction closing in the second half of 2015.



September 2014	11	Wisconsin Electric Power Company

Form 10-Q

4 -- COMMON EQUITY

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



	2014			2013

Non-qualified stock options granted year to date	864,860			1,365,970

Estimated fair value per non-qualified stock option	$	4.18		$	3.45

Assumptions used to value the options using a binomial option pricing model:
Risk-free interest rate	0.1% - 3.0%			0.1% - 1.9%
Dividend yield	3.8		%	3.7		%
Expected volatility	18.0		%	18.0		%
Expected forfeiture rate	2.0		%	2.0		%
Expected life (years)	5.8			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.

The following is a summary of Wisconsin Energy stock option activity by our employees during the three and nine months ended September 30, 2014:



					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of July 1, 2014	7,799,650		$	28.92
Granted	—		$	—
Exercised	(597,341	)	$	23.69
Forfeited	—		$	—
Outstanding as of September 30, 2014	7,202,309		$	29.36

Outstanding as of January 1, 2014	7,688,843		$	26.92
Granted	864,860		$	41.03
Exercised	(1,334,199	)	$	22.79
Forfeited	(17,195	)	$	36.73
Outstanding as of September 30, 2014	7,202,309		$	29.36	5.6	$	98.3

Exercisable as of September 30, 2014	4,434,474		$	23.99	3.9	$	84.3

The intrinsic value of Wisconsin Energy options exercised by our employees was $12.7 million and $28.6 million for the three and nine months ended September 30, 2014, and $1.7 million and $34.9 million for the same periods in 2013, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $30.4 million and $39.9 million for the nine months ended September 30, 2014 and 2013, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was $11.5 million and $14.0 million, respectively.



September 2014	12	Wisconsin Electric Power Company

Form 10-Q

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of September 30, 2014:



	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)
$17.10 to $21.11	1,560,914	$	20.73	3.6	1,560,914	$	20.73	3.6
$23.88 to $29.35	2,629,770	$	24.83	3.7	2,629,770	$	24.83	3.7
$34.88 to $41.03	3,011,625	$	37.78	8.3	243,790	$	35.81	7.6
	7,202,309	$	29.36	5.6	4,434,474	$	23.99	3.9

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the three and nine months ended September 30, 2014:



			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of July 1, 2014	2,804,225		$	3.65
Granted	—		$	—
Vested	(36,390	)	$	3.62
Forfeited	—		$	—
Non-vested as of September 30, 2014	2,767,835		$	3.65

Non-vested as of January 1, 2014	2,289,400		$	3.38
Granted	864,860		$	4.18
Vested	(369,230	)	$	3.26
Forfeited	(17,195	)	$	3.56
Non-vested as of September 30, 2014	2,767,835		$	3.65

As of September 30, 2014, 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 18 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, 2014:



			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2014	101,946
Granted	—		$	—
Released	—		$	—
Forfeited	(1,289	)	$	38.61
Outstanding as of September 30, 2014	100,657

Outstanding as of January 1, 2014	98,226
Granted	51,873		$	40.98
Released	(46,228	)	$	34.31
Forfeited	(3,214	)	$	38.47
Outstanding as of September 30, 2014	100,657

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



September 2014	13	Wisconsin Electric Power Company

Form 10-Q

Energy restricted stock vesting and held by our employees was zero and $2.3 million for the three and nine months ended September 30, 2014, and zero and $2.8 million for the same periods in 2013, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was zero and $0.9 million for the three and nine months ended September 30, 2014, and zero and $1.1 million for the same periods in 2013, respectively.

As of September 30, 2014, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $2.6 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Performance Units: In January 2014 and 2013, the Compensation Committee awarded 224,735 and 230,245 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, 2013 and 2012 vested and were settled during the first quarter of 2014 and 2013, and had a total intrinsic value of $13.1 million and $17.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $4.7 million and $6.2 million, respectively. As of September 30, 2014, total compensation cost related to our share of Wisconsin Energy performance units not yet recognized was approximately $6.8 million, which is expected to be recognized over the next 26 months on a weighted-average basis.

Restrictions: Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. See Note H -- Common Equity in our 2013 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.

5 -- LONG-TERM DEBT

In May 2014, we issued $250 million of 4.25% Debentures due June 1, 2044. The debentures were issued under an existing shelf registration statement filed with the SEC in November 2013.

In April 2014, we retired $300 million of long-term debt that matured.

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.

In May 2013, we retired $300 million of long-term debt that matured.

6 -- FAIR VALUE MEASUREMENTS

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

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

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

Level 1 -- 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



September 2014	14	Wisconsin Electric Power Company

Form 10-Q

in sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments.

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

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

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.

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



Recurring Fair Value Measures	As of September 30, 2014
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	1.3	$	8.4	$	10.1	$	19.8
Total	$	1.3	$	8.4	$	10.1	$	19.8

Liabilities:
Derivatives	$	0.9	$	—	$	—	$	0.9
Total	$	0.9	$	—	$	—	$	0.9



Recurring Fair Value Measures	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	3.2	$	2.3	$	3.5	$	9.0
Total	$	3.2	$	2.3	$	3.5	$	9.0

Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

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.



September 2014	15	Wisconsin Electric Power Company

Form 10-Q

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



	Three Months Ended September 30						Nine Months Ended September 30
	2014			2013			2014			2013
	(Millions of Dollars)

Beginning Balance	$	14.1		$	9.2		$	3.5		$	4.7
Realized and unrealized gains (losses)	—			—			—			—
Purchases	—			—			15.6			10.6
Issuances	—			—			—			—
Settlements	(4.0		)	(3.6		)	(9.0		)	(9.7		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of September 30	$	10.1		$	5.6		$	10.1		$	5.6

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

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

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



	September 30, 2014				December 31, 2013
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.4	$	30.4	$	26.0
Long-term debt, including current portion	$	2,437.0	$	2,697.2	$	2,487.0	$	2,634.7

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.

7-- DERIVATIVE INSTRUMENTS

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

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of September 30, 2014, we recognized $1.3



September 2014	16	Wisconsin Electric Power Company

Form 10-Q

million in regulatory assets and $18.5 million in regulatory liabilities related to derivatives in comparison to $0.3 million in regulatory assets and $8.1 million in regulatory liabilities as of December 31, 2013.

We record our current derivative assets on the balance sheet in prepayments and other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $1.7 million is recorded in other deferred charges and other assets as of September 30, 2014, and the long-term portion of our derivative liabilities of $0.1 million is recorded in other deferred credit and other liabilities as of September 30, 2014. Our Consolidated Condensed Balance Sheets as of September 30, 2014 and December 31, 2013 include:



	September 30, 2014				December 31, 2013
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	4.2	$	0.9	$	2.8	$	0.1
Fuel Oil	—		—		0.6		—
FTRs	10.1		—		3.5		—
Coal	5.5		—		2.1		0.2
Total	$	19.8	$	0.9	$	9.0	$	0.3

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



	Three Months Ended September 30, 2014				Three Months Ended September 30, 2013
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)

Natural Gas	4.1 million Dth	$	(0.5	)	3.6 million Dth	$	(0.5	)
Fuel Oil	2.6 million gallons	—			2.5 million gallons	(0.1		)
FTRs	6.6 million MWh	2.0			6.9 million MWh	5.4
Total		$	1.5			$	4.8



	Nine Months Ended September 30, 2014			Nine Months Ended September 30, 2013
	Volume	Gains (Losses)		Volume	Gains (Losses)
		(Millions of Dollars)			(Millions of Dollars)

Natural Gas	16.7 million Dth	$	4.9	18.2 million Dth	$	(2.6	)
Fuel Oil	7.0 million gallons	0.6		6.2 million gallons	0.1
FTRs	19.7 million MWh	11.6		19.2 million MWh	11.0
Total		$	17.1		$	8.5

As of September 30, 2014 and December 31, 2013, we posted collateral of $1.3 million and zero, 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.



September 2014	17	Wisconsin Electric Power Company

Form 10-Q

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, 2014 and December 31, 2013.



	September 30, 2014						December 31, 2013
	Derivative			Derivative			Derivative		Derivative
	Asset			Liability			Asset		Liability
	(Millions of Dollars)

Gross Amount Recognized on the Balance Sheet	$	19.8		$	0.9		$	9.0	$	0.3
Gross Amount Not Offset on Balance Sheet (a)	(0.3		)	(0.9		)	—		—
Net Amount	$	19.5		$	—		$	9.0	$	0.3


(a)	Gross Amount Not Offset on Balance Sheet includes cash collateral posted of $0.6 million and zero as of September 30, 2014 and December 31, 2013, respectively.

8 -- BENEFITS

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



	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2014			2013			2014			2013
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.3		$	3.5		$	7.0		$	10.4
Interest cost	14.8			13.1			44.5			39.3
Expected return on plan assets	(19.7		)	(19.3		)	(59.3		)	(57.9		)
Amortization of:
Prior service cost	0.5			0.5			1.5			1.6
Actuarial loss	6.7			10.4			20.2			31.3
Net Periodic Benefit Cost	$	4.6		$	8.2		$	13.9		$	24.7



	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2014			2013			2014			2013
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.0		$	2.4		$	6.0		$	7.1
Interest cost	3.6			3.2			10.8			9.5
Expected return on plan assets	(4.0		)	(3.7		)	(12.1		)	(10.9		)
Amortization of:
Transition obligation	—			—			—			—
Prior service (credit)	(0.4		)	(0.5		)	(1.2		)	(1.4		)
Actuarial loss	—			0.4			0.1			1.1
Net Periodic Benefit Cost	$	1.2		$	1.8		$	3.6		$	5.4

We made no contributions to our qualified benefit plans during the first nine months of 2014 and 2013. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates.



September 2014	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 $2.8 million as of both September 30, 2014 and December 31, 2013.

9 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable segments for the three and nine months ended September 30, 2014 and 2013 is shown in the following table:



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

September 30, 2014
Operating Revenues (a)	$	880.1	$	51.9		$	5.8		$	937.8
Operating Income (Loss)	$	158.5	$	(0.3	)	$	(2.0	)	$	156.2

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

Nine Months Ended

September 30, 2014
Operating Revenues (a)	$	2,579.6	$	458.2		$	32.4		$	3,070.2
Operating Income	$	462.7	$	53.6		$	5.9		$	522.2

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


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

10 -- 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 eight 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 2014	19	Wisconsin Electric Power Company

Form 10-Q

We have approximately $184.4 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, 2014 and 2013 were $39.8 million and $37.8 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

11 -- 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 $9 million to $17 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, 2014, we have established reserves of $10.8 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.

12 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the nine months ended September 30, 2014, we paid $65.6 million in interest, net of amounts capitalized, and paid $15.7 million in income taxes, net of refunds. 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.

As of September 30, 2014 and 2013, the amount of accounts payable related to capital expenditures was $4.8 million and $3.3 million, respectively.

During the nine months ended September 30, 2014 and 2013, our equity in earnings from ATC was $46.4 million and $44.9 million, respectively. During the nine months ended September 30, 2014 and 2013, distributions received from ATC were $37.4 million and $35.5 million, respectively.



September 2014	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, 2014

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the third quarter of 2014 with the third quarter of 2013, including favorable (better (B)) or unfavorable (worse (W)) variances:



	Three Months Ended September 30
	Electric Revenues							MWh
Electric Utility Operations	2014		B (W)			2013		2014	B (W)		2013
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	308.2	$	(24.5	)	$	332.7	2,033.8	(173.9	)	2,207.7
Small Commercial/Industrial	281.8		(6.1		)	287.9		2,343.9	(37.7	)	2,381.6
Large Commercial/Industrial	171.4		(28.8		)	200.2		1,981.0	(345.3	)	2,326.3
Other - Retail	5.3		(0.2		)	5.5		33.4	(1.2	)	34.6
Total Retail	766.7		(59.6		)	826.3		6,392.1	(558.1	)	6,950.2
Wholesale - Other	28.6		(4.0		)	32.6		353.9	(51.9	)	405.8
Resale - Utilities	62.7		17.3			45.4		1,963.7	533.5		1,430.2
Other Operating Revenues	20.9		14.5			6.4		—	—		—
Total	878.9		(31.8		)	910.7		8,709.7	(76.5	)	8,786.2
Electric Customer Choice (a)	1.2		0.9			0.3		595.4	394.9		200.5
Total, including electric customer choice	$	880.1	$	(30.9	)	$	911.0

Weather -- Degree Days (b)
Heating (121 Normal)								175	45		130
Cooling (548 Normal)								352	(188	)	540

(a) Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

(b) 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 decreased by $30.9 million, or 3.4%, when compared to the third quarter of 2013. The most significant factors that caused a change in revenues were:


•	Cooler summer weather decreased electric revenues by an estimated $40.5 million.


•	A $22.8 million decrease in large commercial/industrial sales because of the two iron ore mines switching to an alternative electric supplier in September 2013. 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.


•	A $17.3 million increase in sales for resale resulting from increased sales into the MISO Energy and Operating Reserves Market (MISO Energy Markets) as a result of Michigan's alternative electric supplier program.


•	A $14.5 million increase in other operating revenues, primarily driven by the recognition of $12.6 million related to revenues under the System Support Resource (SSR) agreement with MISO. See Factors Affecting Results, Liquidity and Capital Resources - Electric Transmission and Energy Markets - Restructuring in Michigan, for a discussion of the SSR payments.


•	Wisconsin net retail pricing increases of $10.9 million, which are primarily related to our 2013 Wisconsin Rate Case. For information on the rate order in the 2013 rate case and the 2014 fuel credits, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.

As measured by cooling degree days, the third quarter of 2014 was 34.8% cooler than the same period in 2013 and 35.8% cooler than normal. We believe the cooler weather was the primary driver of reduced sales to our residential



September 2014	21	Wisconsin Electric Power Company

Form 10-Q

and small commercial/industrial customers. Sales to large commercial/industrial customers decreased by 14.8%, primarily because of the loss of the two iron ore mines in Michigan as retail electric customers. If the sales to the mines are excluded, sales to our large commercial/industrial customers decreased 2.3%.

Fuel and Purchased Power

Our fuel and purchased power costs decreased by $2.2 million, or 0.6%, when compared to the third quarter of 2013. This decrease was primarily caused by a 0.9% decrease in total MWh sales, which was partially offset by higher generating costs driven by an increase in natural gas prices as compared to the third quarter of 2013.

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 2014 with the third quarter of 2013. 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 $3.9 million, or 8.1%. Cost of gas sold increased by $3.3 million, or 13.5%, because of an increase in the average cost of delivered gas.



	Three Months Ended September 30
	2014		B (W)			2013
	(Millions of Dollars)

Gas Operating Revenues	$	51.9	$	3.9		$	48.0
Cost of Gas Sold	27.7		(3.3		)	24.4
Gross Margin	$	24.2	$	0.6		$	23.6

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2014 with the third quarter of 2013:



	Three Months Ended September 30
	Gross Margin						Therms
Gas Utility Operations	2014		B (W)		2013		2014	B (W)		2013
	(Millions of Dollars)						(Millions)
Customer Class
Residential	$	16.3	$	0.3	$	16.0	22.2	1.7		20.5
Commercial/Industrial	3.8		—		3.8		14.4	0.4		14.0
Interruptible	0.1		—		0.1		0.5	—		0.5
Total Retail	20.2		0.3		19.9		37.1	2.1		35.0
Transported Gas	3.6		0.1		3.5		65.5	(4.6	)	70.1
Other Operating	0.4		0.2		0.2		—	—		—
Total	$	24.2	$	0.6	$	23.6	102.6	(2.5	)	105.1

Weather -- Degree Days (a)
Heating (121 Normal)							175	45		130

(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 $0.6 million, or approximately 2.5%, when compared to the third quarter of 2013.

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $22.2 million, or approximately 6.6%, when compared to the third quarter of 2013. This decrease was primarily driven by lower benefit costs.



September 2014	22	Wisconsin Electric Power Company

Form 10-Q

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $5.4 million, or approximately 7.8%, when compared to the third quarter of 2013 primarily because of an overall increase in utility plant in service. Our new biomass plant went into service in November 2013.

Treasury Grant

In December 2013, we filed an application with the United States Treasury for a Section 1603 Renewable Energy Treasury Grant (Treasury Grant) related to the construction of our biomass facility. In December 2013, we recognized income related to the Treasury Grant and we deferred as a regulatory liability the grant proceeds that would be returned to customers subsequent to December 31, 2013. In connection with our Wisconsin retail electric rates that became effective January 1, 2013, our Wisconsin retail electric customers began receiving bill credits for the expected grant proceeds plus the related tax benefits. We began to record grant income when the biomass facility was placed into service in the fourth quarter of 2013.

In June 2014, we received approximately $76.2 million related to the Treasury Grant. The PSCW approved escrow accounting for the Treasury Grant and the proceeds we received that exceeded the amounts originally included in rates will be returned to customers in future rate proceedings.

As noted above, our Wisconsin retail electric customers are currently receiving bill credits related to the Treasury Grant plus related tax benefits. During 2014, we are recognizing Treasury Grant income to match the bill credits related to the grant that our Wisconsin retail electric customers are receiving.

Other Income, net



	Three Months Ended September 30
Other Income, net	2014		B (W)			2013
	(Millions of Dollars)

AFUDC - Equity	$	1.2	$	(3.8	)	$	5.0
Gain on Property Sales	0.1		(0.2		)	0.3
Other	0.1		0.8			(0.7		)
Other Income, net	$	1.4	$	(3.2	)	$	4.6

Other income, net decreased by $3.2 million, or approximately 69.6%, when compared to the third quarter of 2013. The decrease in AFUDC - Equity is primarily related to the biomass plant going into service in November 2013.

Interest Expense, net



	Three Months Ended September 30
Interest Expense	2014		B (W)			2013
	(Millions of Dollars)

Gross Interest Costs	$	29.5	$	1.8		$	31.3
Less: Capitalized Interest	0.5		(1.5		)	2.0
Interest Expense, net	$	29.0	$	0.3		$	29.3

Our gross interest costs decreased by $1.8 million, or approximately 5.8%, when compared to the third quarter of 2013 primarily due to lower debt levels and lower average interest rates. Our capitalized interest decreased by $1.5 million primarily because of lower construction work in progress as the biomass plant went into service in November 2013. As a result, our net interest expense decreased by $0.3 million, or 1.0%, as compared to the third quarter of 2013.



September 2014	23	Wisconsin Electric Power Company

Form 10-Q

Income Tax Expense

For the third quarter of 2014, our effective tax rate was 37.6% compared to 36.0% for the third quarter of 2013. This increase in our effective tax rate was primarily due to reduced tax benefits associated with Treasury Grant income and decreased AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2013 Annual Report on Form 10-K.

RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2014

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 2014 with the first nine months of 2013, including favorable (better (B)) or unfavorable (worse (W)) variances:



	Nine Months Ended September 30
	Electric Revenues							MWh
Electric Utility Operations	2014		B (W)			2013		2014	B (W)		2013
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	902.4	$	(10.7	)	$	913.1	5,977.1	(126.5	)	6,103.6
Small Commercial/Industrial	798.4		0.4			798.0		6,682.3	(17.8	)	6,700.1
Large Commercial/Industrial	485.5		(80.9		)	566.4		5,628.6	(1,257.0	)	6,885.6
Other - Retail	16.8		(0.2		)	17.0		107.6	(2.0	)	109.6
Total Retail	2,203.1		(91.4		)	2,294.5		18,395.6	(1,403.3	)	19,798.9
Wholesale - Other	102.3		(7.0		)	109.3		1,430.0	(14.7	)	1,444.7
Resale - Utilities	211.0		119.5			91.5		4,891.0	2,010.1		2,880.9
Other Operating Revenues	59.2		38.3			20.9		—	—		—
Total	2,575.6		59.4			2,516.2		24,716.6	592.1		24,124.5
Electric Customer Choice (a)	4.0		3.7			0.3		1,824.1	1,623.6		200.5
Total, including electric customer choice	$	2,579.6	$	63.1		$	2,516.5

Weather -- Degree Days (b)
Heating (4,320 Normal)								5,184	554		4,630
Cooling (722 Normal)								460	(218	)	678

(a) Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

(b) 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 $63.1 million, or 2.5%, when compared to the first nine months of 2013. The most significant factors that caused a change in revenues were:


•	A $119.5 million increase in sales for resale because of increased sales into the MISO Energy Markets as a result of Michigan's alternative electric supplier program and increased availability of our generating units.


•	A $78.4 million decrease in large commercial/industrial sales because of the two iron ore mines switching to an alternative electric supplier in September 2013.


•	A $38.3 million increase in other operating revenues, primarily driven by the recognition of $34.4 million related to revenues under the SSR agreement with MISO.


•	Wisconsin net retail pricing increases of $29.1 million, which are primarily related to our 2013 Wisconsin Rate Case.


•	Cooler summer weather decreased electric revenues by an estimated $27.8 million.



September 2014	24	Wisconsin Electric Power Company

Form 10-Q

Cooling degree days decreased 32.2% during the first nine months of 2014 as compared to the same period in 2013 due to mild second and third quarters that reduced the cooling load. The unfavorable impact of the cool summer weather was partially offset by the cold winter weather. Residential sales decreased by 2.1%, primarily because of weather. Sales to large commercial/industrial customers decreased by 18.3%, primarily because of the loss of the two iron ore mines in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased 1.1% compared to 2013.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $61.7 million, or 6.9%, when compared to the first nine months of 2013. This increase was primarily caused by a 2.5% increase in total MWh sales and higher generating costs driven by an increase in natural gas prices.

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 2014 with the first nine months of 2013. 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 $153.6 million, or 50.4%, and cost of gas sold increased by $143.7 million, or 78.1%, due to colder weather and an increase in the commodity cost of natural gas.



	Nine Months Ended September 30
	2014		B (W)			2013
	(Millions of Dollars)

Gas Operating Revenues	$	458.2	$	153.6		$	304.6
Cost of Gas Sold	327.8		(143.7		)	184.1
Gross Margin	$	130.4	$	9.9		$	120.5

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2014 with the first nine months of 2013:



	Nine Months Ended September 30
	Gross Margin							Therms
Gas Utility Operations	2014		B (W)			2013		2014	B (W)		2013
	(Millions of Dollars)							(Millions)
Customer Class
Residential	$	87.1	$	5.6		$	81.5	279.3	31.0		248.3
Commercial/Industrial	28.9		3.3			25.6		163.1	22.9		140.2
Interruptible	0.3		(0.1		)	0.4		3.4	(0.4	)	3.8
Total Retail	116.3		8.8			107.5		445.8	53.5		392.3
Transported Gas	12.6		0.7			11.9		252.7	19.3		233.4
Other	1.5		0.4			1.1		—	—		—
Total	$	130.4	$	9.9		$	120.5	698.5	72.8		625.7

Weather -- Degree Days (a)
Heating (4,320 Normal)								5,184	554		4,630

(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 $9.9 million, or approximately 8.2%, when compared to the first nine months of 2013. This increase primarily relates to an increase in sales volumes as a result of colder weather during the first nine months of 2014 that increased heating loads. We estimate that weather increased gas margins by approximately $6.7 million. As measured by heating degree days, the first nine months of 2014 were 12.0% colder than the same period in 2013 and 20.0% colder than normal.



September 2014	25	Wisconsin Electric Power Company

Form 10-Q

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $50.9 million, or approximately 5.0%, when compared to the first nine months of 2013. This decrease was primarily driven by lower benefit costs.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $13.5 million, or approximately 6.5%, when compared to the first nine months of 2013, primarily because of an overall increase in utility plant in service. Our new biomass plant went into service in November 2013.

Treasury Grant

For a discussion of the impact of the Treasury Grant on our results of operations, see Results of Operations -- Three Months Ended September 30, 2014 -- Treasury Grant.

Other Income, net



	Nine Months Ended September 30
Other Income, net	2014		B (W)			2013
	(Millions of Dollars)

Gain on Property Sales	$	4.3	$	3.5		$	0.8
AFUDC - Equity	3.0		(10.7		)	13.7
Other	0.7		1.1			(0.4		)
Other Income, net	$	8.0	$	(6.1	)	$	14.1

Other income, net decreased by $6.1 million, or approximately 43.3%, when compared to the first nine months of 2013. The decrease in AFUDC - Equity is primarily related to the biomass plant going into service in November 2013.

Interest Expense, net



	Nine Months Ended September 30
Interest Expense	2014		B (W)			2013
	(Millions of Dollars)

Gross Interest Costs	$	88.8	$	8.4		$	97.2
Less: Capitalized Interest	1.2		(4.5		)	5.7
Interest Expense, net	$	87.6	$	3.9		$	91.5

Our gross interest costs decreased by $8.4 million, or approximately 8.6%, when compared to the first nine months of 2013 primarily due to lower debt levels and lower average interest rates. Our capitalized interest decreased by $4.5 million primarily because of lower construction work in progress as the biomass plant went into service in November 2013. As a result, our net interest expense decreased by $3.9 million, or 4.3%, as compared to the first nine months of 2013.

Income Tax Expense

For the first nine months of 2014, our effective tax rate was 37.1% compared to 35.5% for the first nine months of 2013. This increase in our effective tax rate was primarily due to reduced tax benefits associated with Treasury Grant income and decreased AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2013 Annual Report on Form 10-K. We expect our 2014 annual effective tax rate to be between 37% and 38%.



September 2014	26	Wisconsin Electric Power Company

Form 10-Q

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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



	2014			2013
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	768.0		$	739.3
Investing Activities	$	(399.4	)	$	(405.6	)
Financing Activities	$	(378.3	)	$	(350.7	)

Operating Activities

Cash provided by operating activities increased by $28.7 million during the first nine months of 2014 as compared to the same period in 2013. Higher net income and non-cash charges related to depreciation increased cash provided by operating activities during the first nine months of 2014 as compared to the same period in 2013. Partially offsetting these items was an increase in deferred regulatory assets.

Investing Activities

Cash used in investing activities decreased by $6.2 million during the first nine months of 2014 as compared to the same period in 2013. Cost of removal, net of salvage decreased approximately $8.6 million during the first nine months of 2014 as compared to the same period in 2013. Our capital expenditures increased by $14.1 million during the first nine months of 2014 as compared to the same period in 2013, primarily because of starting conversion of the fuel source for Valley Power Plant (VAPP) from coal to natural gas.

Financing Activities

Cash used in financing activities increased by $27.6 million during the first nine months of 2014 as compared to the same period in 2013. We paid $100.0 million of special dividends to Wisconsin Energy during the first nine months of 2014 to balance our capital structure, which was partially offset by a $75.7 million decrease in the repayment of short-term debt in 2014 as compared to the same period in 2013.

CAPITAL RESOURCES AND REQUIREMENTS

Working Capital

As of September 30, 2014, our current liabilities exceeded our current assets by approximately $4.5 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 repay our debt obligations if necessary.

Liquidity

We anticipate meeting our capital requirements during the remainder of 2014 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.



September 2014	27	Wisconsin Electric Power Company

Form 10-Q

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, 2014, we had approximately $494.9 million of available, undrawn lines under our bank back-up credit facility, and approximately $170.7 million of commercial paper outstanding that was supported by the available lines of credit. During the first nine months of 2014, our maximum commercial paper outstanding was $401.0 million with a weighted-average interest rate of 0.21%.

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, 2014:



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

$	500.0	$	5.1	$	494.9	December 2017

This facility has a renewal provision for two one-year extensions, subject to lender approval.

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, 2014, 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.

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.

In August 2014, Fitch Ratings affirmed our ratings and stable ratings outlook.

In June 2014, Standard and Poor's Ratings Services affirmed our ratings and stable ratings outlook.

In June 2014, Moody's Investors Service affirmed our ratings and stable ratings outlook.

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, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

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 2013 Annual Report on Form 10-K for additional information related to our credit rating risk.

Capital Requirements

Capital Expenditures: Capital requirements during the remainder of 2014 are expected to be principally for upgrading our electric and gas distribution systems. We estimate that we will spend approximately $530 million on capital expenditures during 2014.

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 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



September 2014	28	Wisconsin Electric Power Company

Form 10-Q

that is material to our investors. For further information, see Note 10 -- 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 $26.5 billion as of September 30, 2014 compared with $27.2 billion as of December 31, 2013.

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 2013 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 have been placed into 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.

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.

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) in June 2013 resolving the claim, as well as several other warranty claims. This settlement did not have a material impact to our financial statements. We resolved an additional warranty claim with Bechtel in April 2014 which also did not have a material impact. The parties continue to work through one remaining item.

See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2013 Annual Report on Form 10-K for additional information on PTF.

RATES AND REGULATORY MATTERS

2015 Wisconsin Rate Case: On May 30, 2014, we applied to the PSCW for a biennial review of costs and rates.

We engaged in settlement discussions related to this review, facilitated by PSCW Staff, with the Citizens Utility Board, the Wisconsin Industrial Energy Group and the Wisconsin Paper Council. As a result of these discussions, we agreed with the three customer groups on the following:


•	We are requesting a rate increase of $41.5 million (1.43%), excluding fuel, for our Wisconsin retail electric customers in 2015; or $52.3 million (1.81%) when including estimated fuel costs for 2015. This increase reflects an offset of $26.2 million (0.91%) related to bill credits. Other than the expiration of the bill credits, no adjustment to electric base rates would be made in 2016.


•	We are requesting a rate decrease of $10.7 million (2.39%) for our natural gas customers in 2015, with no rate adjustment in 2016.


•	We are requesting rate increases in 2015 of $0.5 million (2.10%) and $0.8 million (4.56%) for our downtown Milwaukee and Milwaukee County steam customers, respectively, with no rate adjustments in 2016.

In addition, the parties have agreed that our authorized return on equity should be set at 10.2%. The agreement calls for our financial common equity component to remain the same.

We anticipate a final written order from the PSCW by the end of the year.



September 2014	29	Wisconsin Electric Power Company

Form 10-Q

2013 Wisconsin Rate Case: In March 2012, we initiated rate proceedings with the PSCW. In December 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%) of bill credits related to the proceeds of the Treasury Grant, including related tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133 million (4.8%) for 2013.


•	An electric rate increase for our Wisconsin electric customers of approximately $28 million (1.0%) for 2014, and a $45 million (1.6%) reduction in bill credits.


•	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 rates reflect a $6.4 million reduction in bad debt expense.


•	An increase of approximately $1.3 million (6.0%) for our downtown Milwaukee 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 Treasury Grant.

2014 Fuel Cost Plan Request: In July 2013, we filed our 2014 fuel cost plan with the PSCW requesting authority to decrease Wisconsin retail electric customers' rates approximately $36 million in the form of a fuel credit primarily related to a reduction in delivered coal costs. The plan was approved by the PSCW on December 20, 2013.

Renewable Energy Portfolio: We constructed a 50 MW biomass facility at Domtar Corporation's Rothschild, Wisconsin paper mill site that went into commercial operation in November 2013. Wood waste and wood shavings are used to produce renewable electricity and will also support Domtar's sustainable papermaking operations. The final cost of completing this project was $269.0 million, excluding AFUDC.

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 of our 2013 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 (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, 2014 through May 31, 2015. 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 were served on an interruptible tariff rate, switched to an alternative electric supplier in September 2013. In addition, other smaller retail customers have switched to an alternative electric supplier.

We have taken, and will continue to take, multiple steps to mitigate the financial impacts associated with the loss of these customers. In August 2013, we filed a request with MISO to suspend the operation of all five units at Presque Isle Power Plant (PIPP) located in the Upper Peninsula of Michigan. In October 2013, MISO informed us that the operation of all units is necessary to maintain reliability in the Upper Peninsula of Michigan.

On January 30, 2014, we entered into an SSR agreement with MISO to recover costs for operating and maintaining the units. The agreement was effective February 1, 2014, has a one year term, and specifies monthly payments to



September 2014	30	Wisconsin Electric Power Company

Form 10-Q

Wisconsin Electric of $4.4 million to cover fixed costs. The agreement also provides for the payment of our variable costs to operate and maintain the plant. MISO filed the SSR agreement with FERC on January 31, 2014, and on April 1, 2014, FERC conditionally accepted the agreement as filed, subject to further review and FERC order. We began receiving SSR payments from MISO in the second quarter retroactive to the agreement's effective date of February 1, 2014.

In addition, we issued a request for proposals regarding the potential purchase of PIPP in January 2014. We did not receive any proposals by the March 3, 2014 deadline. Based upon our evaluation and the lack of interest to purchase the plant, on April 15, 2014, we filed a request with MISO to retire PIPP effective October 15, 2014. On May 28, 2014, MISO informed us that they had determined the operation of all five units at PIPP is necessary for reliability purposes; therefore, the units will continue to be designated as SSR units, unless an alternative solution is identified through the stakeholder planning process.

We entered into a new SSR agreement with MISO, effective October 15, 2014, that would cover the operating costs of PIPP through December 2015. The new SSR agreement also includes, among other things, costs to comply with the Mercury and Air Toxic Standards (MATS) and a return on and of our investment in the plant. The new agreement is based on projected costs and is subject to a true-up mechanism. The estimated monthly payments under this agreement are approximately $8.1 million. The new SSR agreement is subject to FERC approval and is expected to replace the prior SSR agreement.

MISO, subject to direction from the FERC, is responsible for allocating the SSR costs to various market participants within the MISO footprint. Several interested parties, including the PSCW and the MPSC, have filed complaints with the FERC regarding the allocation of SSR costs among the different jurisdictions. On October 9, 2014, we filed a request with the FERC to hold in abeyance the change in the allocation of SSR costs among the different jurisdictions until the affected parties have further discussion regarding this issue.

See Factors Affecting Results, Liquidity and Capital Resources - Industry Restructuring and Competition in Item 7 of our 2013 Form 10-K for additional information regarding the impact of industry restructuring in Michigan, as well as information regarding other restructuring matters and MISO.

ENVIRONMENTAL MATTERS

Air Quality

National Ambient Air Quality Standards

8-hour Ozone Standards: In April 2004, the United States Environmental Protection Agency (EPA) designated 10 counties in southeastern Wisconsin as non-attainment areas for the 1997 8-hour ozone ambient air quality standard. The EPA has since redesignated all of these counties to attainment. In 2008, the EPA issued an additional, more stringent 8-hour ozone standard, and made final attainment designations for this revised standard in 2012. In April 2012 and May 2012, the EPA designated Sheboygan County and the eastern portion of Kenosha County, respectively, as 2008 8-hour ozone standard non-attainment areas. The net result of all of these actions is that construction permitting for all of our Wisconsin power plants, except the Pleasant Prairie Power Plant, is expected to be subject to less stringent permitting requirements. In addition, modifications to these facilities should no longer be required to obtain emission offsets. So long as eastern Kenosha County remains an ozone non-attainment area, the Pleasant Prairie Power Plant will continue to be subject to more stringent permitting requirements and offset provisions.

In January 2010, the EPA announced its decision to further lower the 2008 8-hour ozone standard. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard. In January 2014, environmental groups petitioned the U.S. District Court for the Northern District of California to order the EPA to propose a new ozone standard by the end of 2014 and to finalize the standard by October 2015. We expect the EPA to lower the 8-hour ozone standard from its current level. The impact, if any, of a revised standard will depend on how much it is lowered, but could result in widespread areas of the country not being able to meet the new standard.

Sulfur Dioxide Standard: In June 2010, the EPA issued a new 1-Hour Sulfur Dioxide (SO₂) National Ambient Air Quality Standard (NAAQS) that became effective in August 2010. This standard represents a significant change



September 2014	31	Wisconsin Electric Power Company

Form 10-Q

from the previous SO₂ standard, and NAAQS in general, since attainment designations were to be based primarily on modeling rather than monitoring. Typically, attainment designations are based on monitored data. The EPA has since issued two technical assistance documents for comment in 2013, and in May 2014, issued the proposed Data Requirements Rule that would establish procedures and timelines for implementation of the standard. The proposed rule describes the EPA's plans for allowing the states to use either monitoring or modeling to make designations.

We filed comments on the proposed rule with the EPA in July 2014, and proposed a special reliability exclusion for PIPP which would recognize our request to retire the facility, and would exclude it from further modeling or monitoring requirements and subsequent emission reductions. As proposed, the rule affords state agencies latitude in rule implementation. States would have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection). If the state chooses modeling and the sources in an area do not make reductions by 2017, and as a consequence the area is classified as non-attainment, then they would have to make emission reductions by 2023. Alternatively, if a state opted out of modeling and instead chose monitoring, and subsequently monitored non-attainment, then it would face a 2026 compliance date. A non-attainment designation could have negative impacts for a localized geographic area, including permitting constraints for the subject source and for other new or existing sources in the area.

We believe our fleet (with the exception of PIPP) is well positioned to meet this regulation once it is finalized. If PIPP is still operating in the 2021-2022 timeframe, it will likely need additional SO₂ reductions in order to comply with the standard.

Mercury and Other Hazardous Air Pollutants: In December 2011, the EPA issued the final 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 planning for the addition of a dry sorbent injection system for further control of mercury and acid gases at the plant to comply with MATS. 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. In February 2012, the EPA issued final technical revisions to the rule and issued a draft final rule which together delay the implementation date for certain penalty provisions that could potentially impact the PIPP and increase the number of allowances issued to the states of Michigan and Wisconsin. We and a number of other parties sought judicial review of the rule. In April 2014, the United States Supreme Court issued a decision largely upholding the rule and remanding it for further proceedings consistent with the Court's order. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision that clears the way for the EPA to begin implementing CSAPR in 2015. In light of this decision and further proceedings by the appellate court, we are re-evaluating the rule and availability of allowances in Michigan for PIPP to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. We also expect to have excess allowances available to sell from our Wisconsin power plants.

Clean Air Visibility Rule: The EPA issued the Clean Air Visibility Rule in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to the EPA's CAIR. The pollutants from power plants that reduce visibility include fine particulate matter or compounds that contribute to fine particulate formation, NO_x, SO₂ and ammonia.

In June 2012, the EPA promulgated a Federal Implementation Plan that approves reliance on the CSAPR to satisfy electric generating unit BART requirements for NO_x and SO₂. In December 2012, the EPA approved the remainder of Michigan's regional haze State Implementation Plan (SIP).

In August 2012, the EPA approved Wisconsin's regional haze SIP, which also relies on the CSAPR to satisfy electric generating unit BART requirements for NO_x and SO₂.



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The U.S. Supreme Court decision in April 2014 that upheld the CSAPR allows for the final regional haze rulemaking activities and requirements for NO_x and SO₂ to proceed. We believe we will be well positioned to meet the Clean Air Visibility rule based on air quality control system additions that are already in place or planned for our generating facilities.

Valley Power Plant Conversion: In August 2012, we announced plans to convert the fuel source for VAPP from coal to natural gas. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC. We filed for a Certificate of Authority from the PSCW in April 2013, and received final written approval in March 2014. Construction is underway with the conversion of two boilers scheduled for completion in 2014, and the remaining two boilers scheduled for completion in 2015.

Greenhouse Gas (GHG) Regulations: The EPA issued proposed guidelines relating to GHG emissions from existing generating units on June 18, 2014, and has announced plans to issue final rules by June 2015. The EPA also published proposed performance standards for modified and reconstructed generating units. The proposed guidelines seek to attain state-specific GHG rate reductions by 2030, and require states to submit plans as early as June 30, 2016. Single states requesting a one year extension would be required to submit plans by June 30, 2017, and states that are part of a multi-state plan that request a two year extension would be required to submit plans by June 30, 2018. The EPA is seeking GHG rate reductions in Wisconsin of 34% and in Michigan of 31% by 2030, with interim reduction goals beginning in 2020 of 30% and 27% respectively, with compliance determined by averaging reductions over the ten year period of 2020 to 2029. The proposed program consists of building blocks that include a combination of power plant efficiency improvements, increased reliance on combined cycle gas units, adding new renewable energy resources, and increased demand side management. We are in the process of reviewing the proposed guidelines to determine the potential impacts to our operations, but the guidelines as currently proposed could result in significant additional compliance costs, including capital expenditures, impact how we operate our existing fossil fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.

In June 2014, in Utility Air Regulatory Group v. EPA, the U.S. Supreme Court struck down a portion of the EPA’s program for permitting GHG emissions under the Prevention of Significant Deterioration (PSD) and Title V programs. The Court held that a facility’s GHG emissions alone cannot trigger a requirement to obtain a permit and that the EPA did not have the authority to “tailor” the statutory permitting thresholds. The Court also upheld those portions of the EPA’s program that provide for implementation of GHG emissions limits based on the application of Best Available Control Technology for facilities already subject to PSD or Title V permitting requirements for other pollutants. We do not expect that this decision will have a material impact on our facilities.

Water Quality

Clean Water Act: Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The EPA finalized rules for new facilities (Phase I) in 2001. Final rules for cooling water intake systems at existing facilities (Phase II) were promulgated in 2004. However, as a result of litigation, the EPA withdrew the Phase II rule in July 2007 and advised states to use their best professional judgment in making BTA decisions while the rule remains suspended.

The EPA proposed a new Phase II rule in 2011, and issued the final Phase II rule on May 16, 2014. The new rule will apply to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the Phase I rules.

The new rule allows facility owners to select from seven options available to meet the impingement mortality (IM) reduction standard. BTA determinations will be made over the next several years by the WDNR and MDEQ, subject to EPA oversight, when facility permits are reissued. Based upon our assessment, we believe that the existing technologies at our generating facilities will allow us to demonstrate that, other than VAPP, all of our facilities satisfy the IM BTA standard. We plan to install fish protection screens at VAPP that we expect will meet the IM BTA standard.

The BTA determinations for entrainment mortality (EM) reduction will be made by the WDNR and MDEQ on a case-by-case basis. The new rule requires state permitting agencies to determine EM BTA on a site-specific basis taking into consideration several factors. Because the entrainment reduction standard is a site-specific determination, we



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cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new requirements.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2013 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 2013, we began testing various combinations of sub-bituminous coal and bituminous coal to identify any equipment limitations, and making equipment modifications to the units. On July 7, 2014, we filed an application requesting the PSCW to approve $25 million of additional capital for plant modifications that will enable testing of up to 100% Powder River Basin (sub-bituminous) coal. 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 a Notice of Violation (NOV) to us in January 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) 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 Units 1 and 4 to remain out of service until at least the first half of 2015. In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR may revise the regulations applicable to Units 1 and 4 and allow those units to restart.

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 for alleged violations of air management statutes and rules. In June 2014, we settled with the Department of Justice and paid $50,000 in costs and penalties.

Pursuant to the terms of the administrative order with the WDNR, we received an “after the fact” permit in connection with the work we completed in 2000 and 2002. On October 24, 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit.

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, 2013. 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 2013 Annual Report on Form 10-K, as well as Note 6 -- Fair Value Measurements and Note 7 -- Derivative Instruments in the Notes to Consolidated Condensed Financial Statements in this report.



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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 2013 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.

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

We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition and results of operations. We have identified a number of these risk factors in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013, which risk factors are incorporated herein by reference. Other than as set forth below, there have been no material changes to these risk factors. You should carefully consider all of these risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.



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Risks Related to Legislation and Regulation

We may face significant costs to comply with the regulation of greenhouse gas emissions.

The regulation of GHG emissions continues to be a top priority for the President's administration. In June 2013, the President issued a presidential memorandum instructing the EPA to, among other things, issue rules pertaining to GHG emissions from both new and existing plants.

In June 2012, the U.S. Court of Appeals for the D.C. Circuit upheld the EPA's authority to regulate GHG emissions. The EPA is pursuing regulation of GHG emissions using its existing authority under the Clean Air Act. In September 2013, the EPA withdrew its 2012 proposed New Source Performance Standards GHG emissions rule, and issued new proposed rules with GHG limits for new fossil fueled power plants. The rule would 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 issued a proposed rule on June 18, 2014, and is expected to issue a final rule by June 2015. The proposed rule would require states to submit SIPs as early as June 30, 2016. Single states requesting a one year extension would be required to submit SIPs by June 30, 2017, and states that are part of a multi-state plan that request a two year extension would be required to submit SIPs by June 30, 2018. We are in the process of reviewing the proposed rule to determine the potential impacts to our operations. We expect that these regulations as currently proposed would impact how we operate our existing facilities, particularly our fossil fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.

Legislation to regulate GHG emissions and establish renewable and efficiency standards has also been considered on the state level. Both Wisconsin and Michigan have adopted renewable portfolio standards and energy optimization (efficiency) targets.

Despite a United States Supreme Court decision where the Court ruled that the plaintiffs in the litigation did not have standing to claim nuisance under federal common law due to the release of GHG into the atmosphere by the defendants, states and environmental groups have lawsuits pending against electric utilities and others to force reductions in GHG emissions based upon their contribution to the alleged public nuisance of climate change.

There is no guarantee that we will be allowed to fully recover costs incurred to comply with legislation, regulation or orders requiring a reduction in GHG emissions or that cost recovery will not be delayed or otherwise conditioned. Any legislation or regulation that may ultimately be adopted, either at the federal or state level, designed to reduce GHG emissions could have a material adverse impact on our electric generation and natural gas distribution operations. Such regulation could make some of our electric generating units uneconomic to maintain or operate, and could adversely affect our future results of operations, cash flows and possibly financial condition if such costs are not recovered through regulated rates.

A decrease in the return on equity earned by participants in MISO could have a negative impact on our results of operations.

On June 19, 2014, FERC issued an order revising its methodology for determining the base return on equity for jurisdictional electric utilities, including transmission owners. FERC expects its new methodology will narrow the "zone" of reasonable returns on equity. FERC also indicated that it will continue its policy that an electric utility's total return on equity is limited to the zone of reasonableness. FERC has set a complaint against MISO and the transmission owners participating in MISO challenging the owners' 12.38% base return on equity for hearing. There is a risk that FERC would reduce the allowed return on equity ATC receives as a transmission owning member of MISO, which ultimately could reduce our earnings with respect to our investment in ATC.



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ITEM 6. EXHIBITS



Exhibit No.

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:	October 31, 2014	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer



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WISCONSIN ELECTRIC POWER CO - FORM 10-Q - October 31, 2014

Attached files

WISCONSIN ELECTRIC POWER CO Reports