WISCONSIN ELECTRIC POWER CO - Annual Report: 2014 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 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

_______________________________________



	Securities Registered Pursuant to Section 12(b) of the Act: None

	Securities Registered Pursuant to Section 12(g) of the Act:
	Serial Preferred Stock, 3.60% Series, $100 Par Value
	Six Per Cent. Preferred Stock, $100 Par Value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] No [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes [ ] No [X]

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this Chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in the definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

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. (Check one):

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]

As of June 30, 2014 (and currently), all of the common stock of Wisconsin Electric Power Company is held by Wisconsin Energy Corporation.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (January 31, 2015):

Common Stock, $10 Par Value, 33,289,327 shares outstanding

_______________________________________

Documents Incorporated by Reference

Portions of Wisconsin Electric Power Company's Definitive information statement on Schedule 14C for its Annual Meeting of Stockholders, to be held on April 30, 2015, are incorporated by reference into Part III hereof.



	2014 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY

FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2014

_____________________________________



TABLE OF CONTENTS
Item			Page

PART I

1. Business			10

1A. Risk Factors			23

1B. Unresolved Staff Comments			31

2. Properties			32

3. Legal Proceedings			33

4. Mine Safety Disclosures			34

Executive Officers of the Registrant			34

PART II

5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			35

6. Selected Financial Data			36

7. Management's Discussion and Analysis of Financial Condition and Results of Operations			37

7A. Quantitative and Qualitative Disclosures About Market Risk			63

8. Financial Statements and Supplementary Data			64
	Consolidated Income Statements		64
	Consolidated Balance Sheets -- Assets		65
	Consolidated Balance Sheets -- Capitalization and Liabilities		66
	Consolidated Statements of Cash Flows		67
	Consolidated Statements of Capitalization		68
	Consolidated Statements of Common Equity		69
	Notes to Consolidated Financial Statements		70
	Note A	Summary of Significant Accounting Policies	70
	Note B	Recent Accounting Pronouncements	73
	Note C	Regulatory Assets and Liabilities	73
	Note D	Proposed Acquisition of Integrys by Wisconsin Energy	74
	Note E	Asset Retirement Obligations	75
	Note F	Variable Interest Entities	75
	Note G	Income Taxes	75
	Note H	Common Equity	78
	Note I	Preferred Stock	81
	Note J	Long-Term Debt and Capital Lease Obligations	81
	Note K	Short-Term Debt	83
	Note L	Derivative Instruments	84



	3	Wisconsin Electric Power Company



	2014 Form 10-K

TABLE OF CONTENTS - (Cont'd)



Item			Page
	Note M	Fair Value Measurements	85
	Note N	Benefits	87
	Note O	Segment Reporting	92
	Note P	Related Parties	93
	Note Q	Commitments and Contingencies	95
	Note R	Supplemental Cash Flow Information	96
	Note S	Subsequent Event	96
	Report of Independent Registered Public Accounting Firm		97

9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			98

9A. Controls and Procedures			98

9B. Other Information			98

PART III

10. Directors, Executive Officers and Corporate Governance of the Registrant			99

11. Executive Compensation			99

12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			99

13. Certain Relationships and Related Transactions, and Director Independence			100

14. Principal Accountant Fees and Services			100

PART IV

15. Exhibits and Financial Statement Schedules			100

Schedule II - Valuation and Qualifying Accounts			102

Signatures			103

Exhibit Index			E-1



	4	Wisconsin Electric Power Company



	2014 Form 10-K



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
OC 1		Oak Creek expansion Unit 1
OC 2		Oak Creek expansion Unit 2
PIPP		Presque Isle Power Plant
PSGS		Paris Generating Station
PWGS 1		Port Washington Generating Station Unit 1
PWGS 2		Port Washington Generating Station Unit 2
VAPP		Valley Power Plant

Other Affiliates
ATC		American Transmission Company LLC
DATC		Duke-American Transmission Company

Federal and State Regulatory Agencies
DOE		United States Department of Energy
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
Act 141		2005 Wisconsin Act 141
BART		Best Available Retrofit Technology
BTA		Best Technology Available
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CO₂		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
EM		Entrainment Mortality
GHG		Greenhouse Gas
IM		Impingement Mortality



	5	Wisconsin Electric Power Company



	2014 Form 10-K



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:

MATS		Mercury and Air Toxics Standards
NAAQS		National Ambient Air Quality Standards
NO_x		Nitrogen Oxide
PM_2.5		Fine Particulate Matter
PSD		Prevention of Significant Deterioration
SIP		State Implementation Plan
SO₂		Sulfur Dioxide
WPDES		Wisconsin Pollutant Discharge Elimination System

Other Terms and Abbreviations
AQCS		Air Quality Control System
ARRs		Auction Revenue Rights
Bechtel		Bechtel Power Corporation
Compensation Committee		Compensation Committee of the Board of Directors of Wisconsin Energy
CPCN		Certificate of Public Convenience and Necessity
ERISA		Employee Retirement Income Security Act of 1974
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
GCRM		Gas Cost Recovery Mechanism
HSR Act		Hart-Scott-Rodino Antitrust Improvements Act of 1976
Integrys		Integrys Energy Group, Inc.
LMP		Locational Marginal Price
Merger Agreement		Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys and Wisconsin Energy Corporation
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Market
Moody's		Moody's Investor Service
NYMEX		New York Mercantile Exchange
OTC		Over-the-Counter
Point Beach		Point Beach Nuclear Power Plant
PTF		Power the Future
RTO		Regional Transmission Organization
S&P		Standard & Poor's Ratings Services
SSR		System Support Resource
Treasury Grant		Section 1603 Renewable Energy Treasury Grant
UPPCO		Upper Peninsula Power Company

Measurements
Btu		British Thermal Unit(s)
Dth		Dekatherm(s) (One Dth equals one million Btu)
kW		Kilowatt(s) (One kW equals one thousand Watts)
kWh		Kilowatt-hour(s)



	6	Wisconsin Electric Power Company



	2014 Form 10-K



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:

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
ARO		Asset Retirement Obligation
GAAP		Generally Accepted Accounting Principles
OPEB		Other Post-Retirement Employee Benefits



	7	Wisconsin Electric Power Company



	2014 Form 10-K

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 damage; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; 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.


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


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

•

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 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 are, or may become, subject; changes in



	8	Wisconsin Electric Power Company



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION - (Cont'd)	2014 Form 10-K

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.


•	The direct or indirect effect on our business resulting from terrorist incidents and the threat of terrorist incidents, including cyber intrusion.


•	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 (DATC) 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 factors discussed elsewhere in this report and that may be disclosed from time to time in our Securities and Exchange Commission (SEC) filings or in other publicly disseminated written documents.

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.



	9	Wisconsin Electric Power Company

PART I


ITEM 1.	BUSINESS

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 1,133,600 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 475,100 gas customers in Wisconsin and approximately 440 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our business segments, see Results of Operations in Item 7 and Note O -- Segment Reporting in the Notes to Consolidated Financial Statements in Item 8.

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), a non-utility company that was formed in 2001 to design, construct, own and lease to us the generating capacity included in Wisconsin Energy's Power the Future (PTF) strategy. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies."

Proposed Acquisition: On June 22, 2014, Wisconsin Energy entered into an agreement to acquire Integrys Energy Group, Inc. (Integrys). The proposed acquisition is scheduled to close in the second half of 2015, and is subject to the receipt of various approvals. The combined company will serve approximately 1.5 million electric customers, 2.8 million gas customers and own approximately 60% of ATC. For additional information on this acquisition, see Note D -- Proposed Acquisition of Integrys by Wisconsin Energy in the Notes to Consolidated Financial Statements in Item 8.

Bostco is our non-utility subsidiary that develops and invests in real estate. As of December 31, 2014, Bostco had $28.4 million of assets.

Our annual and periodical filings with the SEC are available, free of charge, through Wisconsin Energy's Internet website www.wisconsinenergy.com. These documents are available as soon as reasonably practicable after such materials are filed (or furnished) with the SEC.

UTILITY OPERATIONS

ELECTRIC UTILITY OPERATIONS

We are the largest electric utility in the state of Wisconsin. We generate and distribute electric energy in a territory that includes southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and the Upper Peninsula of Michigan.

We participate in the Midcontinent Independent System Operator (MISO) Energy Markets. The competitiveness of our generation offered in the MISO Energy Markets affects how our generating units are dispatched and how we buy and sell power. For further information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Electric Sales

Our electric energy deliveries, which include supply and distribution sales to our retail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier, totaled approximately 35.1 million MWh during 2014 and approximately 33.0 million MWh during 2013. We had approximately



	10	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

1,133,600 electric customers as of December 31, 2014 and 1,128,300 electric customers as of December 31, 2013.

We are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits, Certificates of Public Convenience and Necessity (CPCNs) or boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities. We also sell wholesale electric power within the MISO Energy Markets.

Electric Sales Growth: Our service territory experienced steady retail sales in 2014 after accounting for changes associated with customers switching to alternative electric suppliers. Assuming continuing improvement in the economy over the five-year forecast horizon, we presently anticipate that total retail electric kWh sales and the associated peak electric demand will grow at a compound annual rate of about 0.5% over the next five years. These estimates assume normal weather.

Sales to Large Electric Retail Customers: We provide electric utility service to a diversified base of customers in such industries as paper, foundry, food products and machinery production, as well as to large retail chains.

Prior to September 2013, our largest retail electric customers were two iron ore mines located in the Upper Peninsula of Michigan. The mines were served on an interruptible tariff rate and switched to an alternative electric supplier effective September 1, 2013. The combined electric energy sales to the two mines accounted for 3.7% and 6.6% of our total electric utility energy sales during 2013 and 2012, respectively. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition in Item 7.

Effective February 1, 2015, the two mines returned as retail customers. We expect to defer the net revenue from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in future rate proceedings. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice.

Sales to Wholesale Customers: During 2014, we sold wholesale electric power to two rural cooperatives, and two municipal joint action agencies located in the states of Wisconsin and Michigan. Our wholesale electric energy sales were also made to one other public utility in the region under rates approved by the Federal Energy Regulatory Commission (FERC). Wholesale sales accounted for approximately 5.7% of our total electric energy sales and 3.9% of total electric operating revenues during 2014, compared with 6.1% of total electric energy sales and 4.3% of total electric operating revenues during 2013.

Sales for Resale: During 2014, the majority of our sales for resale were sold to one Regional Transmission Organization (RTO), at market rates based on availability of our generation and RTO demand. Sales for resale accounted for approximately 19.9% of our total electric energy sales and 7.8% of total electric operating revenues during 2014, compared with 13.6% of total electric energy sales and 4.3% of total electric operating revenues during 2013.

Electric System Reliability Matters: Our electric sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. The Public Service Commission of Wisconsin (PSCW) has planning reserve requirements consistent with the MISO calculated planning reserve margin. The Michigan Public Service Commission (MPSC) has not yet established guidelines in this area. In accordance with the MISO calculated planning reserve margin requirements, we had adequate capacity to meet MISO calculated planning reserve margin during 2014 and expect to have adequate capacity to meet the planning reserve margin requirements during 2015. For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Competition

Retail electric customers in Wisconsin currently do not have the ability to choose their electric supplier. It is uncertain when, if ever, retail access might be implemented in Wisconsin. However, we attempt to attract new customers into our service territory to increase sales in order to allocate the recovery of our costs among a larger customer base. The regulated energy industry continues to experience significant structural changes, which could eventually lead to increased competition in Wisconsin.



	11	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Michigan has adopted retail choice which allows customers to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service. We continue providing distribution and customer service functions regardless of the customer's power supplier. See Factors Affecting Results, Liquidity and Capital Resources - Industry Restructuring and Competition - Restructuring in Michigan, for a discussion of the impact of customers switching to an alternative electric supplier in Michigan on our electric sales.

We compete with other utilities for sales to municipalities and cooperatives. We also compete with other utilities and marketers in the wholesale electric business. Our wholesale sales are impacted by availability, wholesale electric prices, market conditions and fuel costs.

Electric Supply

Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to maintain a stable, reliable and affordable supply of electricity. We supply a significant amount of electricity to our customers from power plants that we own or lease. We supplement our internally generated power supply with long-term power purchase agreements, including the Point Beach Nuclear Power Plant (Point Beach) power purchase agreement discussed later in this report and through spot purchases in the MISO Energy Markets.

Our dependable capability by fuel type as of December 31 is shown below:



	Dependable Capability in MW (a)
	2014	2013	2012
Coal	3,707	3,822	3,828
Natural Gas - Combined Cycle	1,082	1,082	1,090
Natural Gas/Oil - Peaking Units (b)	962	962	962
Renewables (c)	155	155	107
Natural Gas - Steam Turbine (d)	118	—	—
Total	6,024	6,021	5,987


(a)	Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. We are a summer peaking electric utility. The values were established by tests and may change slightly from year to year.


(b)	The dual-fueled facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local gas distribution company that delivers gas to the plants.


(c)	Includes hydroelectric, biomass and wind generation.


(d)	The Natural Gas - Steam Turbine represents the dependable capability associated with the Valley unit converted from coal to natural gas in November 2014. The remaining unit will be converted in 2015.

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2014, as well as an estimate for 2015:



	Estimate		Actual
	2015		2014		2013		2012
Coal	56.2	%	55.7	%	53.6	%	43.0	%
Natural Gas - Combined Cycle	11.2	%	8.8	%	10.1	%	15.9	%
Renewables	3.5	%	3.8	%	3.3	%	3.0	%
Natural Gas - Steam Turbine	0.5	%	0.2	%	—	%	—	%
Natural Gas/Oil - Peaking Units	0.3	%	0.2	%	0.2	%	0.7	%
Net Generation	71.7	%	68.7	%	67.2	%	62.6	%
Purchased Power	28.3	%	31.3	%	32.8	%	37.4	%
Total	100.0	%	100.0	%	100.0	%	100.0	%



	12	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Our average fuel and purchased power costs per MWh by fuel type for the years ended December 31 are shown below:



	2014		2013		2012
Coal	$	27.68	$	27.97	$	30.71
Natural Gas - Combined Cycle	$	40.64	$	32.22	$	23.62
Natural Gas/Oil - Peaking Units	$	129.83	$	83.95	$	53.40
Purchased Power	$	47.47	$	43.74	$	41.92

Historically, coal has been purchased under long-term contracts, which helped with price stability. Coal and associated transportation services have continued to see volatility in pricing due to changing domestic and world-wide demand for coal and the impacts of diesel costs which are incorporated into fuel surcharges on rail transportation.

We have a PSCW-approved hedging program to help manage our natural gas price risk. This hedging program is generally implemented on a 36-month forward-looking basis. Proceeds related to the natural gas hedging program are reflected in the average costs of natural gas and purchased power shown above.

Coal-Fired Generation

Coal Supply: We diversify the coal supply for our power plants by purchasing coal from mines in Wyoming and Montana, as well as from various other states. During 2015, 87% of our projected coal requirements of 12.5 million tons are under contracts which are not tied to 2015 market pricing fluctuations. At the end of 2014, our coal-fired generation consisted of six operating plants with a dependable capability of approximately 3,707 MW.

The annual tonnage amounts contracted for 2015 through 2017 are as follows:



Year		Annual Tonnage
		(Thousands)

2015		10,843
2016		5,887
2017		3,417

Coal Deliveries: Approximately 100% of our 2015 coal requirements are expected to be delivered by unit trains owned or leased by us. The unit trains will transport coal for the Oak Creek and Pleasant Prairie Power Plants from Wyoming mines, and transport coal for the Oak Creek expansion units from Pennsylvania and Wyoming. Montana and Wyoming coal for the Presque Isle Power Plant (PIPP) is transported via rail to Superior, Wisconsin, placed in dock storage and reloaded into lake vessels for plant delivery. Existing coal inventory will be drawn down to fuel Valley Power Plant (VAPP) until its conversion to natural gas is complete, which is scheduled to occur in 2015. Milwaukee County Power Plant will be fueled with coal currently stored at a dock in the Port of Milwaukee and additional small volume purchases will be shipped to that location.

Certain of our coal transportation contracts contain fuel cost adjustments that are tied to changes in diesel fuel and crude oil prices. Currently, diesel fuel contracts are not actively traded; therefore, we use financial heating oil contracts to mitigate risk related to diesel fuel prices. We have a PSCW-approved hedging program that allows us to hedge up to 75% of our potential risks related to fuel surcharge exposure. The costs of this program are included in our fuel and purchased power costs.

Environmental Matters: For information regarding emission restrictions, especially as they relate to coal-fired generating facilities, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7.



	13	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Natural Gas-Fired Generation

Our natural gas-fired generation consists of five operating plants with a dependable capability of approximately 1,982 MW as of December 31, 2014.

We purchase natural gas for these plants on the spot market from gas marketers, utilities and producers and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements intended to support the plants' variable usage.

We have a program that allows us to hedge up to 65% of our estimated gas usage for electric generation in order to help manage our natural gas price risk. The costs of this program are included in our fuel and purchased power costs.

Oil-Fired Generation

Fuel oil is used for the combustion turbines at the Germantown Power Plant units 1-4, boiler ignition and flame stabilization at PIPP, and diesel engines at the Pleasant Prairie Power Plant and VAPP. Our oil-fired generation had a dependable capability of approximately 180 MW as of December 31, 2014. Our natural gas-fired peaking units have the ability to burn oil if natural gas is not available due to delivery constraints. Fuel oil requirements are purchased under agreements with suppliers.

Renewable Generation

Hydroelectric: Our hydroelectric generating system consists of 13 operating plants with a total installed capacity of approximately 88 MW and a dependable capability of approximately 39 MW as of December 31, 2014. Of these plants, 12 plants (86 MW of installed capacity) have long-term licenses from FERC. The other plant, with an installed generating capacity of approximately 2 MW, is operated under a permit granted by another federal agency.

Wind: We have four wind sites, consisting of 200 turbines with an installed capacity of 338 MW and a dependable capability of 66 MW.

Biomass: We constructed a biomass-fueled power plant 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 a dependable capability of approximately 50 MW of electric power as well as steam to support Domtar's papermaking operations.

Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. The following table identifies our power purchase commitments as of December 31, 2014 with unaffiliated parties for the next five years:



Year		MW (a)

2015		1,267
2016		1,267
2017		1,267
2018		1,267
2019		1,267


(a)	MW do not include leased generation from PTF units.

The above commitments include approximately 1,030 MW per year related to the Point Beach long-term power purchase agreement. The balance of these purchased power commitments is an arrangement where we buy power at a price determined monthly based on a formula tied to the gas price index.



	14	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Electric Transmission and Energy Markets

American Transmission Company: ATC is a regional transmission company that owns, maintains, monitors and operates electric transmission systems in Wisconsin, Michigan, Illinois and Minnesota. ATC is expected to provide comparable service to all customers, including us, and to support effective competition in energy markets without favoring any market participant. ATC is regulated by FERC for all rate terms and conditions of service and is a transmission-owning member of MISO. MISO maintains operational control of ATC's transmission system, and we are a non-transmission owning member and customer of MISO. We owned approximately 23.0% of ATC as of December 31, 2014 and 2013. For additional information, see Note P -- Related Parties in the Notes to Consolidated Financial Statements.

In April 2011, ATC and Duke Energy announced the creation of a joint venture, Duke-American Transmission Company, that will build, own and operate new electric transmission infrastructure in North America to address increasing demand for affordable, reliable transmission capacity. In April 2013, DATC acquired a 72% interest in California's Path 15 transmission line. DATC continues to evaluate new projects and opportunities, along with participating in the competitive bidding process on projects it considers to be viable. These projects are located in the service territories of several different regional transmission organizations around the country.

MISO: In connection with its status as a FERC approved RTO, MISO developed and operates the Energy and Operating Reserves Markets, which includes its bid-based energy markets and ancillary services market. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas and Missouri. This new region is referred to as MISO South. We are participants in the West region. These changes have not had a material impact on our allocation of MISO costs, and we do not expect them to have a material impact in the future. For further information on MISO and the MISO Energy Markets, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition - Electric Transmission, Capacity and Energy Markets in Item 7.



	15	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Electric Utility Operating Statistics

The following table shows certain electric utility operating statistics for the past five years:



SELECTED ELECTRIC UTILITY OPERATING DATA

Year Ended December 31	2014		2013		2012		2011		2010

Operating Revenues (Millions)
Residential	$	1,199.3	$	1,208.6	$	1,163.9	$	1,159.2	$	1,114.3
Small Commercial/Industrial	1,052.9		1,048.0		1,013.6		1,006.9		922.2
Large Commercial/Industrial	637.0		711.9		744.3		763.7		677.1
Other - Retail	23.0		23.4		22.8		22.9		21.9
Total Retail Revenues	2,912.2		2,991.9		2,944.6		2,952.7		2,735.5
Wholesale - Other	131.9		143.7		144.4		154.0		134.6
Resale - Utilities	264.1		143.2		53.4		69.5		40.4
Other Operating Revenues	87.8		28.4		51.5		35.1		25.8
Total	3,396.0		3,307.2		3,193.9		3,211.3		2,936.3
Electric Customer Choice (a)	5.1		1.5		—		—		—
Total Operating Revenues, including customer choice	$	3,401.1	$	3,308.7	$	3,193.9	$	3,211.3	$	2,936.3

MWh Sales (Thousands)
Residential	7,946.3		8,141.9		8,317.7		8,278.5		8,426.3
Small Commercial/Industrial	8,805.1		8,860.4		8,860.0		8,795.8		8,823.3
Large Commercial/Industrial	7,393.3		8,673.4		9,710.7		9,992.2		9,961.5
Other - Retail	148.7		152.3		154.8		153.6		155.3
Total Retail Sales	24,293.4		25,828.0		27,043.2		27,220.1		27,366.4
Wholesale - Other	1,852.8		1,953.5		1,566.6		2,024.8		2,004.6
Resale - Utilities	6,497.9		4,382.7		1,642.4		2,065.7		1,103.8
Total Electric Sales	32,644.1		32,164.2		30,252.2		31,310.6		30,474.8
Electric Customer Choice (a)	2,440.0		813.0		—		—		—
Total MWh Delivered	35,084.1		32,977.2		30,252.2		31,310.6		30,474.8

Customers - End of Year (Thousands)
Residential	1,015.0		1,010.5		1,008.2		1,005.5		1,003.6
Small Commercial/Industrial	115.4		114.6		114.3		113.8		113.5
Large Commercial/Industrial	0.7		0.7		0.7		0.7		0.7
Other	2.5		2.5		2.5		2.5		2.4
Total Customers	1,133.6		1,128.3		1,125.7		1,122.5		1,120.2

Customers - Average (Thousands)	1,130.6		1,126.9		1,123.8		1,121.0		1,118.7

Degree Days (b)
Heating (6,601 Normal)	7,616		7,233		5,704		6,633		6,183
Cooling (732 Normal)	464		688		1,041		793		944


(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.



	16	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

GAS UTILITY OPERATIONS

We are authorized to provide retail gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits, CPCNs or boundary agreements with other utilities. We also transport customer-owned gas. Our gas utility operates in three distinct service areas: west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties, Wisconsin.

Gas Deliveries

Our gas utility business is highly seasonal due to the heating requirements of residential and commercial customers, and annual gas sales are impacted by the variability of winter temperatures.

Total gas therms delivered, including customer-owned transported gas, were approximately 983.5 million therms during 2014, a 6.4% increase compared with 2013. As of December 31, 2014, we were transporting gas for approximately 580 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 34.9% of the total volumes delivered during 2014, 35.4% during 2013 and 42.6% during 2012. We had approximately 475,100 and 471,300 gas customers as of December 31, 2014 and 2013, respectively. Our peak daily send-out during 2014 was 852,086 Dth on January 6, 2014.

Sales to Large Gas Customers: We provide gas utility service to a diversified base of industrial customers who are largely within our electric service territory. Major industries served include paper, food products, chemicals and fabricated metal products.

Gas Deliveries Growth: We currently forecast total retail therm deliveries (excluding natural gas deliveries for generation) to grow at a compound annual rate of 0.5% over the five-year period ending December 31, 2019. This forecast reflects a current year weather normalized sales level and normal weather.

Competition

Competition in varying degrees exists between natural gas and other forms of energy available to consumers. A number of our large commercial and industrial customers are dual-fuel customers that are equipped to switch between natural gas and alternate fuels. We are allowed to offer lower-priced gas sales and transportation services to dual-fuel customers. Under gas transportation agreements, customers purchase gas directly from gas marketers and arrange with interstate pipelines and us to have the gas transported to their facilities. We earn substantially the same margin (difference between revenue and cost of gas) whether we sell and transport gas to customers or only transport their gas.

Our ability to maintain our share of the industrial dual-fuel market depends on our success and the success of third-party gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating competitively-priced transportation service for those customers that desire to buy their own gas supplies.

Federal and state regulators continue to implement policies to bring more competition to the gas industry. While the gas utility distribution function is expected to remain a highly regulated, monopoly function, the sale of the natural gas commodity and related services are expected to remain subject to competition from third parties. It remains uncertain if and when the current economic disincentives for small firm customers to choose an alternative gas commodity supplier may be removed such that we begin to face competition for the sale of gas to those customers.

Gas Supply, Pipeline Capacity and Storage

We have been able to meet our contractual obligations with both our suppliers and our customers.

Pipeline Capacity and Storage: The interstate pipelines serving Wisconsin originate in major gas producing areas of North America: the Oklahoma and Texas basins, the Gulf of Mexico, western Canada and the Rocky Mountains. We have contracted for long-term firm capacity from a number of these sources. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.



	17	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Due to the daily and seasonal variations in gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage inventory levels at approximately 33% of forecasted winter demand; November through March is considered the winter season. Storage capacity, along with our gas purchase contracts, enables us to manage significant changes in daily demand and to optimize our overall gas supply and capacity costs. We generally inject gas into storage during the spring and summer months when demand is lower and withdraw it in the winter months. As a result, we can contract for less long-line pipeline capacity during periods of peak usage than would otherwise be necessary and can purchase gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.

We hold daily transportation and storage capacity entitlements with interstate pipeline companies as well as other service providers under varied-length long-term contracts.

Term Gas Supply: We have contracts for firm supplies with terms in excess of 30 days with suppliers for gas acquired in the Chicago, Illinois market hub and in the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices. Combined with our storage capability, management believes that the volume of gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand.

Secondary Market Transactions: Pipeline long-line and storage capacity and gas supplies under contract can be resold in secondary markets. Local distribution companies, like our gas operations, must contract for capacity and supply sufficient to meet the firm peak-day demand of their customers. Peak or near peak demand days generally occur only a few times each year. The secondary markets facilitate higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to rate payers, subject to our approved Gas Cost Recovery Mechanism (GCRM). During 2014, we continued to participate in the secondary markets. See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 for information on the GCRM.

Spot Market Gas Supply: We expect to continue to make gas purchases in the 30-day spot market as price opportunity and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase spot gas.

Hedging Gas Supply Prices: We have PSCW approval to hedge (i) up to 60% of planned winter and (ii) up to 30% of planned summer flowing gas supply using a mix of New York Mercantile Exchange (NYMEX) based natural gas options and natural gas future contracts. Those approvals allow us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through our GCRM. Hedge targets (volumes) are provided annually to the PSCW as part of our three-year gas supply plan and risk management filing.

To the extent that opportunities develop and physical supply operating plans are supportive, we also have PSCW approval to utilize NYMEX based natural gas derivatives to capture favorable forward market price differentials. That approval provides for 100% of the related proceeds to accrue to our GCRM.



	18	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Gas Utility Operating Statistics

The following table shows certain gas utility operating statistics for the past five years:



SELECTED GAS UTILITY OPERATING DATA

Year Ended December 31	2014		2013			2012		2011		2010

Operating Revenues (Millions)
Residential	$	390.5	$	296.0		$	250.7	$	304.1	$	310.6
Commercial/Industrial	201.6		138.4			115.4		149.9		151.3
Interruptible	2.9		2.4			2.3		2.8		3.1
Total Retail Gas Sales	595.0		436.8			368.4		456.8		465.0
Transported Gas	16.8		16.0			15.1		15.0		14.2
Other Operating Revenues	2.4		(0.9		)	1.6		5.5		2.4
Total Operating Revenues	$	614.2	$	451.9		$	385.1	$	477.3	$	481.6

Therms Delivered (Millions)
Residential	399.3		380.8			294.3		339.4		321.8
Commercial/Industrial	236.2		210.9			165.3		198.7		184.5
Interruptible	4.9		5.4			5.0		5.3		5.5
Total Retail Gas Sales	640.4		597.1			464.6		543.4		511.8
Transported Gas	343.1		327.6			344.5		294.4		300.8
Total Therms Delivered	983.5		924.7			809.1		837.8		812.6

Customers - End of Year (Thousands)
Residential	435.6		432.1			429.6		427.1		425.6
Commercial/Industrial	38.9		38.6			38.5		38.5		38.3
Transported Gas	0.6		0.6			0.5		0.4		0.4
Total Customers	475.1		471.3			468.6		466.0		464.3

Customers - Average (Thousands)	472.6		469.7			466.9		464.7		462.9

Degree Days (a)
Heating (6,601 Normal)	7,616		7,233			5,704		6,633		6,183


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

STEAM UTILITY OPERATIONS

Our steam utility generates, distributes and sells steam supplied by our VAPP and Milwaukee County Power Plant. We operate a district steam system in downtown Milwaukee and the near south side of Milwaukee. Steam is supplied to this system from VAPP. We also operate the steam production and distribution facilities of the Milwaukee County Power Plant located on the Milwaukee County Grounds in Wauwatosa, Wisconsin.

Annual sales of steam fluctuate from year to year based upon system growth and variations in weather conditions. During 2014, the steam utility had $44.1 million of operating revenues from the sale of 2,865 million pounds of steam compared with $39.6 million of operating revenues from the sale of 2,750 million pounds of steam during 2013. As of December 31, 2014 and 2013, steam was used by approximately 440 customers and 445 customers, respectively, for processing, space heating, domestic hot water and humidification.



	19	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

UTILITY RATE MATTERS

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7.

REGULATION

We are a holding company because of our ownership interest in ATC, but are exempt from the requirements of the Public Utility Holding Company Act of 2005.

We are subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities and modify certain other aspects of energy regulations and Federal tax policies applicable to us. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by FERC, which established mandatory electric reliability standards and which has the authority to levy monetary sanctions for failure to comply with these standards.

We are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the state of Wisconsin, standards of service, issuance of securities, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. We are also subject to the regulation of the PSCW as to certain levels of short-term debt obligations. We are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state of Michigan, except as to the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Almost all of our hydroelectric facilities are regulated by FERC. We are subject to the regulation of FERC with respect to wholesale power service, electric reliability requirements and accounting and with respect to our participation in the interstate natural gas pipeline capacity market. For information on how rates are set, see Rates and Regulatory Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7.

The following table compares our operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2014:



	2014				2013				2012
	Amount		Percent		Amount		Percent		Amount		Percent
	(Millions of Dollars)
Electric
Wisconsin - Retail	$	2,889.9	85.0	%	$	2,874.8	86.9	%	$	2,808.4	87.9	%
Michigan - Retail	58.8		1.7	%	147.0		4.4	%	187.8		5.9	%
FERC - Wholesale	396.0		11.6	%	286.9		8.7	%	197.7		6.2	%
FERC - SSR	56.4		1.7	%	—		—	%	—		—	%
Total	3,401.1		100.0	%	3,308.7		100.0	%	3,193.9		100.0	%

Gas - Wisconsin - Retail	614.2		100.0	%	451.9		100.0	%	385.1		100.0	%

Steam - Wisconsin - Retail	44.1		100.0	%	39.6		100.0	%	34.3		100.0	%
Total Utility Operating Revenues	$	4,059.4			$	3,800.2			$	3,613.3

For additional information on our business operations in Michigan, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition - Michigan Business in Item 7.

Our operations are also subject to regulations, where applicable, of the United States Environmental Protection Agency (EPA), the Wisconsin Department of Natural Resources (WDNR), the Michigan Department of Environmental Quality (MDEQ) and the Michigan Department of Natural Resources.



	20	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Public Benefits and Renewable Portfolio Standard

2005 Wisconsin Act 141 (Act 141) established a goal that 10% of electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we must meet certain minimum requirements for renewable energy generation. For the years 2010 through 2014, we were required to increase our percentage of total retail energy sales provided by renewable sources (renewable energy percentage) by at least two percentage points from our baseline renewable percentage of 2.27%. As of December 31, 2014, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. We expect to be in compliance with this standard. In addition, under this Act, 1.2% of utilities' annual operating revenues were required to be used to fund energy conservation programs in 2014. The funding required by Act 141 for 2015 is also 1.2% of annual operating revenues.

Public Act 295 enacted in Michigan requires 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. We are currently in compliance with this requirement. Public Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

For additional information on Act 141 and our renewable portfolio, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters - Renewables, Efficiency and Conservation in Item 7.

ENVIRONMENTAL COMPLIANCE

Our operations are subject to extensive environmental regulations by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental statutes and regulations or revisions to existing laws, including for example, additional regulation of greenhouse gas emissions, coal combustion products, air emissions or wastewater discharges, could significantly increase these environmental compliance costs.

Anticipated expenditures for environmental compliance and remediation issues for the next three years are included in estimated capital expenditures described in Liquidity and Capital Resources -- Capital Requirements in Item 7. For discussion of additional environmental issues, see Environmental Matters in Item 3. For further information concerning air and water quality standards and rulemaking initiated by the EPA, including estimated costs of compliance, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7. For a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites and air quality, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.

Compliance with federal, state and local environmental protection requirements resulted in capital expenditures of approximately $1.0 million in 2014 compared with $24.7 million in 2013. Expenditures incurred during 2014 and 2013 primarily included costs associated with the installation of pollution abatement facilities at our power plants. No future expenditures are currently anticipated. Operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $110.3 million and $92.9 million during 2014 and 2013, respectively.

Coal Combustion Product Fills and Landfills

We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Some early designed and constructed coal combustion product landfills, which we used prior to developing this program, may allow the release of low levels of constituents resulting in the need for various levels of remediation. Where we have become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. In addition, fill areas for coal ash were used prior to the introduction of landfill regulations. Sites currently undergoing review include the following:



	21	Wisconsin Electric Power Company



ITEM 1. BUSINESS - (Cont'd)	2014 Form 10-K

Oak Creek Site Landfills: Groundwater near the sites, located in the Village of Caledonia and the City of Oak Creek, Wisconsin, was found to contain levels of molybdenum above the allowable limit prompting us to begin investigation in 2009 for the source of the molybdenum. Our study indicates that the groundwater impacts are naturally occurring or are from other sources based on groundwater flow direction and increasing concentrations of elements deeper in the ground. The WDNR began sampling work in 2011 to identify the source of the groundwater impacts and issued its report in 2013. The WDNR study found that the data was inconclusive as to the source causing the groundwater impacts. We reviewed the WDNR report and provided technical comments further supporting our position that regional ground water impacts are not a result of coal ash management activities at the Oak Creek site. The Wisconsin Department of Health Services has since increased the allowable limit for molybdenum in groundwater, and the WDNR sent a letter to residents with private wells that exceeded the earlier limit with information about the change. For additional information regarding molybdenum, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters -- Land Quality -- New Coal Combustion Products Regulation in Item 7.

OTHER

Research and Development: We had immaterial research and development expenditures in the last three years, primarily for improvement of service and abatement of air and water pollution by our electric utility operations. Research and development activities include work done by employees, consultants and contractors, plus sponsorship of research by industry associations.

Employees: As of December 31, 2014, we had 3,823 total employees, of which 2,492 were represented under labor agreements with the following bargaining units:



	Number of Employees	Expiration Date of Current Labor Agreement
Local 2150 of International Brotherhood of Electrical Workers	1,728	August 15, 2017
Local 420 of International Union of Operating Engineers	524	September 30, 2017
Local 2006 Unit 1 of United Steel Workers	133	April 30, 2017
Local 510 of International Brotherhood of Electrical Workers	107	October 31, 2016
Total	2,492



	22	Wisconsin Electric Power Company



	2014 Form 10-K


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. You should carefully consider the following 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.

Risks Related to Legislation and Regulation

Our business is significantly impacted by governmental regulation.

We are subject to significant state, local and federal governmental regulation. We are subject to regulation by the PSCW of retail electric, gas and steam rates in the state of Wisconsin, standards of service, issuance of securities, short-term debt obligations, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. In addition, we are subject to regulation by the MPSC of various matters associated with retail electric service in the state of Michigan, except the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Further, our hydroelectric facilities are regulated by FERC, and FERC also regulates our wholesale power service practices, electric reliability requirements and accounting, and participation in the interstate natural gas pipeline capacity market. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs.

We are obligated to comply in good faith with all applicable governmental rules and regulations. If it is determined that we failed to comply with any applicable rules or regulations, whether through new interpretations or applications of the regulations or otherwise, we may be liable for customer refunds, penalties and other amounts, which could materially and adversely affect our results of operations and financial condition.

The rates we are allowed to charge our customers for electric, natural gas and steam services have the most significant impact on our financial condition, results of operations and liquidity. Within our utility operations, approximately 85% of our 2014 electric revenues were regulated by the PSCW, 2% were regulated by the MPSC and the balance of our electric revenues were regulated by the FERC. All of our natural gas and steam revenues are regulated by the PSCW. Rate regulation is based on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent on regulatory action and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable return on equity. We defer certain costs and revenues as regulatory assets and liabilities for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured, and is subject to review and approval by our regulators. If recovery of regulatory assets is not approved or is no longer deemed probable, these costs would be charged to income in the current period and could have a material adverse impact on our financial results.

We believe we have obtained the necessary permits, approvals and certificates for our existing operations and that our respective businesses are conducted in accordance with applicable laws; however, the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to us cannot be predicted. Changes in regulation, interpretations of regulations or the imposition of additional regulations could influence our operating environment and may result in substantial compliance costs.

Governmental agencies could modify our permits, authorizations or licenses.

We are required to comply with the terms of various permits, authorizations and licenses. These permits, authorizations and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency.

Also, if we are unable to obtain, renew or comply with these governmental permits, authorizations or licenses, or if we are unable to recover any increased costs of complying with additional license requirements or any other



	23	Wisconsin Electric Power Company



ITEM 1A. RISK FACTORS - (Cont'd)	2014 Form 10-K

associated costs in our rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.

We may face significant costs of compliance with existing and future environmental regulations.

Our operations are subject to extensive environmental legislation and regulation by state and federal environmental agencies governing, among other things, air emissions such as Carbon Dioxide (CO₂), Sulfur Dioxide (SO₂), Nitrogen Oxide (NO_x), fine particulates and mercury; water discharges; and management of hazardous, toxic and solid wastes and substances. We incur significant expenditures in complying with these environmental requirements, including expenditures for the installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of our facilities.

The EPA has adopted and is in the process of implementing regulations governing the emission of NO_x, SO₂, fine particulate matter (PM_2.5), mercury and other air pollutants under the Clean Air Act (CAA) through the National Ambient Air Quality Standards (NAAQS), the Mercury and Air Toxics Standards (MATS) rule and other air quality regulations. The EPA has also indicated that it intends to propose rules later this year that will expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters. In addition, the EPA has finalized rules governing cooling water intake structures at our power plants and proposed revisions to the effluent guidelines for steam electric generating plants under the Clean Water Act (CWA). The EPA also adopted the Cross-State Air Pollution Rule (CSAPR), which provides for limits on the interstate transport of NO_x and SO₂ emissions. In April 2014, the United States Supreme Court issued a decision largely upholding CSAPR and remanding it for further proceedings. In October 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision that cleared the way for the EPA to begin implementing CSAPR on January 1, 2015. Although the EPA has finalized some parts of the rule, there are several items that still need to be addressed. Therefore, there is still uncertainty as to what capital expenditures may ultimately be required to comply with these regulations.

We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. For example, we are in the process of converting 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. These and other compliance costs we expect to incur over the next three years are included in the table under "Capital Expenditures" in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations.

Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level which could result in significant additional expenditures, operating restrictions on our facilities and increased compliance costs. In addition, the operation of emission control equipment and regulations on our intake and discharge of water could increase our operating costs and could reduce the generating capacity of our power plants. Additional environmental legislation and regulation and the related compliance costs could affect future unit retirement and replacement decisions.

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines.

In the event we are not able to recover all of our environmental expenditures and related costs from our customers in the future, our results of operations and financial condition could be adversely affected. Further, increased costs recovered through rates could contribute to reduced demand for electricity, which could adversely affect our results of operations, cash flows and financial condition.

Our electric and gas utility businesses are also subject to significant liabilities related to the investigation and remediation of environmental contamination at certain of our current and former facilities, and at third-party owned sites. Due to the potential for imposition of stricter standards and greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate.

Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance and citizen enforcement of environmental requirements has increased generally throughout the U.S. In particular, personal injury, property damage and other claims for damages alleged to have been caused



	24	Wisconsin Electric Power Company



ITEM 1A. RISK FACTORS - (Cont'd)	2014 Form 10-K

by coal combustion residuals and alleged exposure to hazardous materials have become more frequent. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of the facilities that we have previously owned and operated, regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. If we fail (or failed) to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.

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

Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas (GHG) emissions. The regulation of GHG emissions continues to be a top priority for the President's administration.

The EPA is pursuing regulation of GHG emissions under the CAA. The EPA issued new rules with GHG limits for new fossil fueled power plants that became effective in June 2014. The rule does not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines.

With respect to existing generating units, the EPA issued a proposed rule in June 2014, and is expected to issue a final rule by mid-summer 2015. The proposed rule would require states to submit state plans as early as June 30, 2016. Single states requesting a one year extension would be required to submit state 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 state plans 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.

There is no guarantee that we will be allowed to fully recover costs incurred to comply with the impending regulations that will require a reduction in GHG emissions or that cost recovery will not be delayed or otherwise conditioned. These and any other related regulations may cause our environmental compliance spending over the next several years to differ materially from the amounts currently estimated. 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 affect unit retirement and replacement decisions. These regulations could also adversely affect our future results of operations, cash flows and possibly financial condition if such costs are not recovered through regulated rates.

We could be subject to higher costs and penalties as a result of mandatory reliability standards.

We are subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cybersecurity assets. Compliance with the mandatory reliability standards could subject us to higher operating costs. If we were ever found to be in noncompliance with the mandatory reliability standards we could be subject to sanctions, including substantial monetary penalties.

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

In June 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



	25	Wisconsin Electric Power Company



ITEM 1A. RISK FACTORS - (Cont'd)	2014 Form 10-K

MISO, which ultimately could reduce our earnings with respect to our investment in ATC. In fact, during the fourth quarter of 2014, ATC reduced its earnings to reflect the potential for lower allowed returns on equity.

Risks Related to the Operation of Our Business

Our financial performance may be adversely affected if we are unable to successfully operate our facilities.

Our financial performance depends on the successful operation of our electric generating and distribution, as well as our gas distribution, facilities. Operation of these facilities involves many risks, including: operator error and breakdown or failure of equipment processes; fuel supply interruptions; labor disputes; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; cyber security threats; or catastrophic events such as fires, earthquakes, explosions, floods, droughts, pandemic health events such as influenzas or other similar occurrences. Unplanned outages can result in additional maintenance expenses as well as incremental replacement power costs. A decrease in revenues from these facilities or an increase in operating costs could adversely affect our results of operations and cash flows.

Customer growth in our service areas affects our results of operations.

Our results of operations are affected by customer growth in our service areas. Customer growth and energy use can be affected by population growth as well as economic factors in Wisconsin and the Upper Peninsula of Michigan, including job and income growth. Customer growth directly influences the demand for electricity and gas, and the need for additional power generation and generating facilities. Population declines and/or business closings in our service territories or slower than anticipated customer growth has a negative impact on our results of operations and cash flow and could expose us to greater risks of accounts receivable write-offs if customers are unable to pay their bills.

Energy sales are impacted by seasonal factors and varying weather conditions from year-to-year.

Our electric and gas utility businesses are generally seasonal businesses. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results in the future may fluctuate substantially on a seasonal basis. In addition, we have historically had lower revenues and net income when weather conditions are milder. Our rates in Wisconsin are set by the PSCW based on estimated temperatures which approximate 20-year averages. Mild temperatures during the summer cooling season and during the winter heating season will negatively impact the results of operations and cash flows of our electric utility business. In addition, mild temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.

Factors beyond our control could adversely affect project costs and completion of construction projects.

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric and natural gas distribution infrastructure and electric generating facilities. We expect to spend an aggregate of between $2.3 billion and $2.5 billion during the period 2015 to 2019 on capital investments. These types of construction projects are subject to many of the usual construction risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the ability to obtain or the cost of labor or materials; the ability of the contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable law or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy.

Certain of these projects require the approval of our regulators. In the event we receive approval, total costs of a project may be higher than estimated and/or higher than amounts approved by our regulators, and there is no guarantee that we will be allowed to recover these additional costs in rates.



	26	Wisconsin Electric Power Company



ITEM 1A. RISK FACTORS - (Cont'd)	2014 Form 10-K

Severe weather events, such as floods, droughts, tornadoes and blizzards, could result in substantial damage to or limit the operation of our facilities.

Severe weather events could result in substantial damage to our electric generating and distribution facilities, as well as our gas distribution facilities and ATC's transmission lines. Our hydroelectric generation operations could be adversely affected if there is a significant change in water levels in their respective waterways. In addition, a significant reduction in water levels in waterways that supply cooling water to our power plants, whether by drought or otherwise, could restrict or prevent the operation of such facilities.

In the event we experience any of these weather events or other natural disaster, recovery of any costs in excess of any reserves or applicable insurance is subject to the approval of the PSCW and/or MPSC. There is no guarantee that we will be allowed to fully recover any such costs or that cost recovery will not be delayed or otherwise conditioned. Any denial or delay in recovery of any such costs could adversely affect our results of operations and cash flows.

In addition, damages resulting from severe weather events within our service territories may result in the loss of customers and reduced demand for electricity and natural gas for extended periods. Any significant loss of customers or reduction in demand could adversely affect our results of operations and cash flows.

Advances in technology could make our electric generating facilities less competitive.

We generate power at central station power plants to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines and solar cells, which have become more cost competitive. It is possible that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station power electric production. If these technologies became cost competitive and achieved economies of scale, our market share could be eroded, and the value of our generating facilities could be reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.

We could be the subject of cyber intrusions that disrupt our electric generation and gas distribution operations and/or result in security breaches that expose us to a risk of loss or misuse of confidential and proprietary information, litigation and potential liability.

We face the risk of physical and cyber attacks, both threatened and actual, against our generation facilities and electric and natural gas distribution infrastructure, as well as our information and technology systems and network infrastructure, which could adversely impact our ability to generate, support and deliver electricity and natural gas, or otherwise operate our facilities in the most efficient manner or at all.

We operate in an industry that requires the continued operation of sophisticated information technology systems and network infrastructure, which are part of an interconnected regional transmission grid. In addition, in the ordinary course of business, we collect and retain sensitive information including personal identification information about our customers and employees and other confidential information. We face on-going threats to our assets and technology systems. Despite the implementation of strong security measures, all assets and systems are potentially vulnerable to disability, failures or unauthorized access due to human error or physical or cyber attacks. If our assets or systems were to fail, be physically damaged or be breached and were not recovered in a timely manner, we may unable to perform critical business functions, and sensitive and other data could be compromised.

Cyber intrusions, including those targeting the electronic control systems used at our generating facilities and for the electric and gas distribution systems, could result in a full or partial disruption of our electric generation and/or gas distribution operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Furthermore, we may need to obtain more expensive purchased power to meet customer demand for electricity if our electric generating facilities are unable to operate at full capacity as a result of a cyber intrusion. Any resulting loss of revenue or increase in expense could have a material adverse effect on our results of operations, cash flow and financial condition.



	27	Wisconsin Electric Power Company



ITEM 1A. RISK FACTORS - (Cont'd)	2014 Form 10-K

In addition, any theft, loss and/or fraudulent use of customer, stockholder, employee or proprietary data as a result of cyber intrusion or otherwise could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers, stockholders and regulators, among others.

In addition to lost revenues and increased costs that we could incur as a result of a cyber attack, we may be required to incur significant costs associated with governmental actions in response to such attacks or to strengthen our information and electronic control systems. We could also need to obtain insurance coverage related to the threat of such attacks.

Acts of terrorism could materially and adversely affect our financial condition and results of operations.

Our electric generation and gas distribution facilities, including the facilities of third parties on which we rely, could be targets of terrorist activities. A terrorist attack on our facilities (or those of third parties) could result in a full or partial disruption of our ability to generate, transmit, transport, purchase or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations and financial condition.

Failure to attract and retain an appropriately qualified workforce could adversely impact our results of operations.

We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.

Failure of a counterparty to one of our power purchase agreements could have an adverse impact on our results of operations.

We have entered into several power purchase agreements with non-affiliated companies, and continue to look for additional opportunities to enter into these agreements. Currently, sales through power purchase agreements are responsible for approximately 7.8% of our electric revenues. Revenues are dependent on the continued performance by the purchasers of their obligations under the power purchase agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more purchasers could fail to perform their obligations under the power purchase agreements. If this were to occur, we would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase agreement would be reallocated among our retail customers. To the extent there is any regulatory lag to adjust rates, a customer default under a power purchase agreement could have a negative impact on our results of operations and cash flows.

We are subject to risks associated with changing customer behaviors, including energy conservation and the adoption of new technologies.

Changes in customer behaviors in response to changing conditions and preferences or changes in the adoption of technologies could affect the consumption of electricity. Customers could voluntarily reduce their consumption of electricity, natural gas and steam in response to decreases in their disposable income, increases in energy prices and/or individual conservation efforts. With respect to customer behavior, federal and state programs exist to influence how customers use energy. In addition, Wisconsin and Michigan have adopted energy efficiency targets to reduce energy consumption by certain dates. The adoption of technology by customers can have both positive and negative impacts on sales. Many new technologies use less energy than their older counterparts. On the other hand, new technologies such as electric vehicles can create additional demand for energy. As part of our planning process, we estimate the impacts of changes in customer behavior, government programs, energy efficiency mandates and new technologies, but risks remain.



	28	Wisconsin Electric Power Company



ITEM 1A. RISK FACTORS - (Cont'd)	2014 Form 10-K

Any of these matters, as well as any regulatory lag to adjust rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could have a negative impact on our results of operations and cash flows. In addition, any higher costs that are collected through rates could contribute to reduced demand for electricity, natural gas or steam, which could adversely impact our results of operations and financial condition.

Our revenues could be negatively impacted by competitive activity in the wholesale electricity markets.

FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, financial laws and regulations impact hedging and trading based on futures contracts and derivatives that are traded on various commodities exchanges, as well as over-the-counter (OTC). Technology changes in the power and fuel industries also have significant impacts on wholesale transactions and related costs. We currently cannot predict the impact of these and other developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.

Risks Related to Economic and Market Volatility

Our business is dependent on our ability to successfully access capital markets.

We rely on access to short-term and long-term capital markets to support our capital expenditures and other capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities and equity contributions from our parent, Wisconsin Energy. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, under competitive terms and rates. In addition, we rely on a committed bank credit agreement as back-up liquidity which allows us to access the low cost commercial paper markets. If our access to any of these markets were limited, or our cost of capital significantly increased, due to a rating downgrade, an economic downturn or uncertainty, prevailing market conditions, concerns over foreign economic conditions and/or the ability of foreign governments and central banks to respond to changing economic conditions, changes in tax policy, war or the threat of war, the overall health of the utility and financial institution industries, a negative view of the utility industry, bankruptcy or financial distress at a financial institution or sovereign entity or other factors, our ability to implement our business plan could be limited which could materially and adversely affect our results of operations.

We are exposed to risks related to general economic conditions in our service territories.

Our electric and gas utility businesses are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn or disruption of national or international financial markets could adversely affect the financial condition of our customers and demand for their products. Adverse economic conditions in our service territories and/or decreased demand for products produced in our service area could cause a reduction in demand for electricity and/or natural gas that could result in decreased earnings and cash flow. We would also expect our collections of accounts receivable to be adversely impacted.

A downgrade in our credit ratings could negatively affect our ability to access capital at reasonable costs and/or require the posting of collateral.

There are a number of factors that impact our credit ratings, including, without limitation, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We could experience a downgrade in our ratings if the rating agencies determine that the level of business or financial risk of the industry or us has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings. If we are downgraded by the rating agencies, our borrowing costs could increase, funding sources could decrease and, for any downgrade to below investment grade, collateral requirements may be triggered in several contracts.



	29	Wisconsin Electric Power Company



ITEM 1A. RISK FACTORS - (Cont'd)	2014 Form 10-K

An increase in natural gas costs could negatively impact our electric and gas utility operations.

We burn natural gas in several of our peaking power plants and in Port Washington Generating Station Unit 1 (PWGS 1) and Port Washington Generating Station Unit 2 (PWGS 2), and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. Disruption in the supply of natural gas due to a curtailment in production or distribution can increase the cost of natural gas, as can international market conditions and demand for natural gas. In addition, the availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and cost of natural gas. Higher natural gas costs can have the effect of increasing demand for other sources of fuel thereby increasing the costs of those fuels as well. Additionally, high natural gas costs increase our working capital requirements and could adversely impact our collection of accounts receivable.

For Wisconsin customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical two percent fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Our gas distribution business receives dollar for dollar recovery of the cost of natural gas, subject to tolerance bands and prudency review.

We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.

We are dependent on coal for much of our electric generating capacity. Although we generally carry sufficient coal inventory at our generating facilities to mitigate an interruption or decline in supply, there can be no assurance that the inventory will be adequate to fully mitigate all potential reductions in supply. While we have coal supply and transportation contracts in place, there can be no assurance that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. The suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to us, or we may experience operational problems or constraints that prevent us from taking delivery. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Furthermore, demand for coal can impact its availability and cost. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices, or we may be forced to reduce generation at our coal units and replace this lost generation through additional power purchases in the MISO market. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed which could adversely affect our cash flows.

Our electric generation frequently exceeds our customer load. When this occurs, we generally sell the excess generation into the MISO market. If we are unable to run our lower cost units we may lose the ability to engage in these opportunity sales, which may adversely affect our results of operations.

The use of derivative contracts could result in financial losses.

We use derivative instruments such as swaps, options, futures and forwards to manage commodity exposures. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although our hedging programs must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.

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

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



	30	Wisconsin Electric Power Company



ITEM 1A. RISK FACTORS - (Cont'd)	2014 Form 10-K

Michigan has adopted retail choice. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. The two iron ore mines located in the Upper Peninsula of Michigan 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.

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

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

Poor investment performance of benefit plan holdings and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations.

We have significant obligations related to pension and other post-retirement benefit plans. Our cost of providing these plans is dependent upon a number of factors including actual plan experience and assumptions concerning the future, such as earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions to be made to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. A decline in the market value of these assets may increase our funding requirements. Changes in interest rates affect plan liabilities - as rates decrease, the liabilities increase, which could increase our funding requirements. Changes in demographics, such as an increase in the number of retirements or changes in life expectancy assumptions, may also increase our funding requirements. Changes made to the plans may also impact current and future pension costs. In addition, it is possible that medical costs for both active or retired employees may increase at a rate that is significantly higher than we currently anticipate. If we are unable to successfully manage our benefit plan assets and medical costs, our cash flows, financial condition or results of operations could be adversely impacted.

Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business, as well as by international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows and financial position.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.



	31	Wisconsin Electric Power Company



	2014 Form 10-K


ITEM 2.	PROPERTIES

We own our principal properties outright, except that the major portion of our electric utility distribution lines, steam utility distribution mains and gas utility distribution mains and services are located, for the most part, on or under streets and highways and on land owned by others and are generally subject to granted easements, consents or permits. In addition, we lease the PTF generating units.

As of December 31, 2014, we owned, or leased from We Power, the following generating assets:



		No. of	Dependable
		Generating	Capability
Name	Fuel	Units	In MW (a)
Coal-Fired Plants
South Oak Creek	Coal	4	993
Oak Creek Expansion	Coal	2	1,057
Presque Isle	Coal	5	344
Pleasant Prairie	Coal	2	1,188
Valley Power Plant	Coal	1	118
Milwaukee County	Coal	3	7
Total Coal-Fired Plants		17	3,707
Natural Gas-Fired Plants
Valley Power Plant	Gas	1	118
Port Washington Generating Station	Gas	2	1,082
Germantown Combustion Turbines	Gas/Oil	5	258
Concord Combustion Turbines	Gas/Oil	4	352
Paris Combustion Turbines	Gas/Oil	4	352
Other Combustion Turbines & Diesel	Gas/Oil	2	—
Total Natural Gas-Fired Plants		18	2,162
Renewables
Hydro Plants (13 in number)		33	39
Rothschild Biomass Plant	Biomass	1	50
Byron Wind Turbines	Wind	2	—
Blue Sky Green Field	Wind	88	29
Glacier Hills	Wind	90	32
Montfort Wind Energy Center	Wind	20	5
Total Renewables		234	155
Total System		269	6,024


(a)	Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. We are a summer peaking electric utility. The values are established by tests and may change slightly from year to year. Dependable capability for the wind sites is determined based on a capacity factor of approximately 20%.

As of December 31, 2014, we operated approximately 21,457 pole-miles of overhead distribution lines and 24,303 miles of underground distribution cable, as well as approximately 350 distribution substations and 295,461 line transformers.

As of December 31, 2014, our gas distribution system included approximately 9,740 miles of distribution mains connected at 27 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, Northern Natural Pipeline Company and Great Lakes Transmission Company. We have a liquefied natural gas storage plant that converts and stores in liquefied form natural gas received during periods of low consumption. The liquefied natural gas storage plant has a send-out capability of 70,000 Dth per day. Our gas distribution system consists almost entirely of plastic and coated steel pipe.



	32	Wisconsin Electric Power Company



ITEM 2. PROPERTIES - (Cont'd)	2014 Form 10-K

We also own office buildings, gas regulating and metering stations and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services and gas distribution mains and services occupy private property, we have in some, but not all instances, obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.

As of December 31, 2014, the combined steam systems supplied by the VAPP and Milwaukee County Power Plant consisted of approximately 42 miles of both high pressure and low pressure steam piping, nine miles of walkable tunnels and other pressure regulating equipment.


ITEM 3.	LEGAL PROCEEDINGS

In addition to those legal proceedings discussed below, 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 other 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

We are subject to federal, state and certain local laws and regulations governing the environmental aspects of our operations. Management believes that our existing facilities are in material compliance with applicable environmental requirements.

Paris Generating Station: See Factors Affecting Results, Liquidity and Capital Resources -- Other Matters for information concerning a contested case on the replacement of certain turbine blades as part of maintenance performed on Units 1 and 4 at our Paris Generating Station (PSGS).

Solvay Coke and Gas Site: We have been identified as a potentially responsible party at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company owned a parcel of property that is within the property boundaries of the site. In 2007, we and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. Site investigations led to the submission of a draft remedial investigation report to the EPA in June 2014. The EPA issued subsequent comments which we addressed. Under the Administrative Settlement Agreement, we do not admit to any liability for the site, waive any liability defenses, or commit to perform future site remedial activities. Our share of the costs to perform the required work and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported in Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.

See Environmental Compliance in Item 1 and Environmental Matters, Manufactured Gas Plant Sites, and Coal Combustion Product Landfill Sites in Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements which are incorporated by reference herein, for a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites and air quality.

UTILITY RATE MATTERS

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 for information concerning rate matters in the jurisdictions where we do business.

OTHER MATTERS

For information concerning Wisconsin Energy's PTF strategy, including the Settlement Agreement with Bechtel Power Corporation (Bechtel), see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future.



	33	Wisconsin Electric Power Company



	2014 Form 10-K


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.

EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages at December 31, 2014 and positions of our executive officers are listed below along with their business experience during the past five years. All officers are appointed until they resign, die or are removed pursuant to the Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.

Gale E. Klappa. Age 64.


•	Wisconsin Energy -- Chairman of the Board and Chief Executive Officer since May 2004. President from April 2003 to July 2013.


•	Wisconsin Electric -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.


•	Wisconsin Gas -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.


•	Director of Joy Global, Inc. and Badger Meter, Inc.


•	Director of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas since 2003.

Stephen P. Dickson. Age 54.


•	Wisconsin Energy -- Vice President since 2005. Controller since 2000.


•	Wisconsin Electric -- Vice President since 2005. Controller since 2000.


•	Wisconsin Gas -- Vice President since 2005. Controller since 1998.

J. Kevin Fletcher. Age 56.


•	Wisconsin Electric -- Senior Vice President since October 2011.


•	Wisconsin Gas -- Senior Vice President since October 2011.


•	Georgia Power -- Vice President - Community and Economic Development from 2007 to October 2011. Georgia Power is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.

Robert M. Garvin. Age 48.


•	Wisconsin Energy -- Senior Vice President since April 2011.


•	Wisconsin Electric -- Senior Vice President since April 2011.


•	Wisconsin Gas -- Senior Vice President since April 2011.


•	American Transmission Co. -- Vice President and General Counsel from 2009 to April 2011.

J. Patrick Keyes. Age 49.


•	Wisconsin Energy -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.


•	Wisconsin Electric -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.


•	Wisconsin Gas -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.


•	Accenture -- Senior Executive from September 2001 to March 2011.

Allen L. Leverett. Age 48.


•	Wisconsin Energy -- President since August 2013. Executive Vice President from May 2004 to July 2013. Chief Financial Officer from July 2003 to February 2011.


•	Wisconsin Electric -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 to February 2011.


•	Wisconsin Gas -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 to February 2011.



	34	Wisconsin Electric Power Company



EXECUTIVE OFFICERS OF THE REGISTRANT - (Cont'd)	2014 Form 10-K

Susan H. Martin. Age 62.


•	Wisconsin Energy -- Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.


•	Wisconsin Electric -- Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.


•	Wisconsin Gas -- Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.

Certain executive officers also hold offices in Wisconsin Energy's non-utility subsidiaries and our non-utility subsidiary.

PART II


ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

DIVIDENDS

Dividends declared on our common stock during the two most recent fiscal years are set forth below. Dividends were paid entirely in cash. Dividends were paid to our sole common stockholder, Wisconsin Energy. There is no established public trading market for our common stock.



Quarter	2014		2013
	(Millions of Dollars)

First	$	110.0	$	60.0
Second	110.0		110.0
Third	110.0		60.0
Fourth	60.0		110.0
Total	$	390.0	$	340.0

Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the board of directors and will depend upon, among other factors, our earnings, financial condition and other requirements.

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. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. For additional information regarding restrictions on our ability to pay dividends, see Note H -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.



	35	Wisconsin Electric Power Company



	2014 Form 10-K


ITEM 6.	SELECTED FINANCIAL DATA



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA

Financial	2014		2013		2012		2011		2010
Year Ended December 31
Earnings available for common stockholder (Millions)	$	376.7	$	360.0	$	366.1	$	338.4	$	314.2

Operating Revenues (Millions)
Electric	$	3,401.1	$	3,308.7	$	3,193.9	$	3,211.3	$	2,936.3
Gas	614.2		451.9		385.1		477.3		481.6
Steam	44.1		39.6		34.3		39.0		38.8
Total operating revenues	$	4,059.4	$	3,800.2	$	3,613.3	$	3,727.6	$	3,456.7

At December 31 (Millions)
Total assets	$	12,646.7	$	12,285.6	$	12,022.6	$	11,661.3	$	10,170.7
Long-term debt and capital lease obligations (including current maturities)	$	5,233.6	$	5,258.8	$	5,276.8	$	5,022.0	$	4,053.5



CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA

	(Millions of Dollars) (a)
	March				June
Three Months Ended	2014		2013		2014		2013
Operating revenues	$	1,226.7	$	1,004.6	$	905.7	$	880.5
Operating income	$	221.8	$	173.1	$	144.2	$	124.2
Earnings available for common stockholder	$	127.0	$	104.4	$	90.0	$	72.8

	September				December
Three Months Ended	2014		2013		2014		2013
Operating revenues	$	937.8	$	964.6	$	989.2	$	950.5
Operating income	$	156.2	$	164.6	$	128.2	$	144.0
Earnings available for common stockholder	$	89.8	$	98.9	$	69.9	$	83.9


(a)	Quarterly results of operations are not directly comparable because of seasonal and other factors. See Management's Discussion and Analysis of Financial Condition and Results of Operations.



	36	Wisconsin Electric Power Company



	2014 Form 10-K


ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

INTRODUCTION

Wisconsin Electric Power Company, a subsidiary of Wisconsin Energy, is engaged primarily in the business of generating and distributing electricity in Wisconsin and the Upper Peninsula of Michigan, and distributing natural gas in 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.

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

CORPORATE STRATEGY

Business Opportunities

We have two primary investment opportunities and earnings streams: our regulated utility business and our investment in ATC.

Our regulated utility business primarily consists of electric generation assets and the electric and gas distribution assets that serve our electric and gas customers. We operate under a traditional rate regulated cost of service environment. During 2014, our regulated utility business earned $650.4 million of operating income. Over the next five years, we currently expect to invest approximately $2.3 billion to $2.5 billion in this business.

We have a 23.0% ownership interest in ATC, a MISO member company regulated by FERC. Our investment in ATC totaled $372.9 million as of December 31, 2014, and our 2014 pre-tax earnings from ATC totaled $57.9 million. Over the next five years, in addition to any potential investment through our undistributed earnings in ATC, we expect to make capital contributions of approximately $110 million in ATC as it continues to invest in transmission projects.

RESULTS OF OPERATIONS

EARNINGS

2014 vs. 2013: Earnings increased to $376.7 million in 2014 compared with $360.0 million in 2013. Operating income increased $44.5 million between the comparative periods. The increase in operating income was primarily caused by colder winter weather and decreased other operation and maintenance expense.

2013 vs. 2012: Earnings decreased to $360.0 million in 2013 compared with $366.1 million in 2012. The decrease in earnings was due to an increase in net interest expense and a decrease in other income and deductions, offset by an increase in operating income. Operating income increased $22.6 million between the comparative periods, primarily caused by favorable winter weather during 2013 and pricing increases which were partially offset by an increase in operation and maintenance expense and depreciation expense.



	37	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

The following table summarizes our consolidated earnings during 2014, 2013 and 2012:



	2014		2013		2012
	(Millions of Dollars)
Utility Gross Margin
Electric (See below)	$	2,187.1	$	2,164.2	$	2,103.6
Gas (See below)	181.6		173.6		157.4
Steam	30.0		26.0		20.8
Total Gross Margin	2,398.7		2,363.8		2,281.8
Other Operating Expenses
Other operation and maintenance	1,356.4		1,417.3		1,327.8
Depreciation and amortization	295.7		278.6		257.6
Property and revenue taxes	113.6		110.0		113.1
Total Operating Expenses	1,765.7		1,805.9		1,698.5
Treasury Grant	17.4		48.0		—
Operating Income	650.4		605.9		583.3
Equity in Earnings of Transmission Affiliate	57.9		60.2		57.6
Other Income and Deductions, net	8.7		17.4		32.3
Interest Expense, net	116.5		121.4		113.2
Income Before Income Taxes	600.5		562.1		560.0
Income Tax Expense	222.6		200.9		192.7
Preferred Stock Dividend Requirement	1.2		1.2		1.2
Earnings Available for Common Stockholder	$	376.7	$	360.0	$	366.1



	38	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2014 with similar information for 2013 and 2012, including a summary of electric operating revenues and electric sales by customer class:



	Electric Revenues and Gross Margin						MWh Sales
Electric Utility Operations	2014		2013		2012		2014	2013	2012
	(Millions of Dollars)						(Thousands)
Customer Class
Residential	$	1,199.3	$	1,208.6	$	1,163.9	7,946.3	8,141.9	8,317.7
Small Commercial/Industrial	1,052.9		1,048.0		1,013.6		8,805.1	8,860.4	8,860.0
Large Commercial/Industrial	637.0		711.9		744.3		7,393.3	8,673.4	9,710.7
Other - Retail	23.0		23.4		22.8		148.7	152.3	154.8
Total Retail	2,912.2		2,991.9		2,944.6		24,293.4	25,828.0	27,043.2
Wholesale - Other	131.9		143.7		144.4		1,852.8	1,953.5	1,566.6
Resale - Utilities	264.1		143.2		53.4		6,497.9	4,382.7	1,642.4
Other Operating Revenues	87.8		28.4		51.5		—	—	—
Total	3,396.0		3,307.2		3,193.9		32,644.1	32,164.2	30,252.2
Electric Customer Choice (a)	5.1		1.5		—		2,440.0	813.0	—
Total, including electric customer choice	3,401.1		3,308.7		3,193.9


Fuel and Purchased Power
Fuel	656.6		611.1		541.6
Purchased Power	557.4		533.4		548.7
Total Fuel and Purchased Power	1,214.0		1,144.5		1,090.3
Total Electric Gross Margin	$	2,187.1	$	2,164.2	$	2,103.6

Weather -- Degree Days (b)
Heating (6,601 Normal)							7,616	7,233	5,704
Cooling (732 Normal)							464	688	1,041


(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.

Electric Utility Revenues and Sales

2014 vs. 2013: Our electric utility operating revenues increased by $92.4 million, or 2.8%, when compared to 2013. The most significant factors that caused a change in revenues were:


•	A $120.9 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. The margin on these sales is used to reduce fuel costs for our retail customers.


•	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. See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Michigan Business, for a discussion of the impact of industry restructuring in Michigan on our electric sales.


•	A $59.4 million increase in other operating revenues, primarily driven by the recognition of $56.4 million related to revenues under the System Support Resource (SSR) agreement with MISO. See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Michigan Business -- SSR Payments for further discussion.


•	Wisconsin net retail pricing increases of $38.3 million, which are primarily related to our 2013 Wisconsin Rate Case.


•	Unseasonably cool summer weather which decreased electric revenues by an estimated $45.8 million.



	39	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

As measured by cooling degree days, 2014 was 36.6% cooler than normal, and 32.6% cooler than 2013 due to mild second and third quarters. The unfavorable impact of the cool summer weather was partially offset by the cold winter weather. Residential sales decreased by 2.4%, primarily due to the weather. Sales to our large commercial/industrial customers decreased by 14.8% 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%. The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers switched to an alternative electric supplier.

2013 vs. 2012: Our electric utility operating revenues increased by $114.8 million, or 3.6%, when compared to 2012. The most significant factors that caused a change in revenues were:

•

Wisconsin net retail pricing increases of $115.6 million ($177.7 million less $62.1 million related to Section 1603 Renewable Energy Treasury Grant (Treasury Grant) bill credits), which are primarily related to our 2013 Wisconsin Rate Case. For information on the Treasury Grant and the rate order in the 2013 rate case, see Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments and -- Rates and Regulatory Matters, respectively.


•	An $89.8 million increase in sales for resale due to increased sales into the MISO Energy Markets as a result of increased availability of our generating units.


•	A $48.0 million decrease in large commercial/industrial sales due to the two iron ore mines that switched to an alternative electric supplier effective September 1, 2013.


•	A $23.1 million decrease in other operating revenues, primarily driven by the amortization of $25.9 million in 2012 related to proceeds we received as part of a settlement with the United States Department of Energy (DOE) regarding the DOE's failure to remove spent nuclear fuel from Point Beach.


•	A return to more normal summer weather as compared to 2012 that decreased electric revenues by an estimated $17.7 million.

As measured by cooling degree days, 2013 was 5.8% cooler than normal, and 33.9% cooler than 2012. Residential sales decreased by 2.1%, primarily due to the weather. Sales to our large commercial/industrial customers decreased by 10.7% 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 3.0%. Wholesale - Other sales increased 24.7% primarily due to increased off-peak energy sales which generate lower incremental revenue because the majority of our wholesale revenue is tied to demand.

Electric Fuel and Purchased Power Expenses

2014 vs. 2013: Our electric fuel and purchased power costs increased by $69.5 million, or approximately 6.1%, when compared to 2013. This increase was primarily caused by a 1.5% increase in total MWh sales and higher generating costs driven by an increase in natural gas prices.

2013 vs. 2012: Our electric fuel and purchased power costs increased by $54.2 million, or approximately 5.0%, when compared to 2012. This increase was primarily caused by a 6.3% increase in total MWh sales, partially offset by a decrease in our average cost of fuel because of outage timing and a decrease in coal costs.



	40	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

Gas Utility Revenues, Gross Margin and Therm Deliveries

The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2014, 2013 and 2012.



Gas Utility Operations	2014		2013		2012
	(Millions of Dollars)

Operating Revenues	$	614.2	$	451.9	$	385.1
Cost of Gas Sold	432.6		278.3		227.7
Gross Margin	$	181.6	$	173.6	$	157.4

We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under our GCRM. Our average cost of gas per therm during 2014, 2013 and 2012 was $0.68, $0.47 and $0.49, respectively. The following table compares our gas utility gross margin and therm deliveries by customer class during 2014, 2013 and 2012:



	Gross Margin						Therm Deliveries
Gas Utility Operations	2014		2013		2012		2014	2013	2012
	(Millions of Dollars)						(Millions)
Customer Class
Residential	$	121.2	$	117.8	$	106.1	399.3	380.8	294.3
Commercial/Industrial	41.1		37.5		33.0		236.2	210.9	165.3
Interruptible	0.4		0.5		0.5		4.9	5.4	5.0
Total Retail	162.7		155.8		139.6		640.4	597.1	464.6
Transported Gas	17.3		16.5		16.5		343.1	327.6	344.5
Other	1.6		1.3		1.3		—	—	—
Total	$	181.6	$	173.6	$	157.4	983.5	924.7	809.1

Weather -- Degree Days (a)
Heating (6,601 Normal)							7,616	7,233	5,704


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

2014 vs. 2013: Our total retail gas margin increased by $6.9 million, or approximately 4.4%, when compared to 2013, primarily because of colder winter weather in 2014. We estimate that colder winter weather increased gas margins by approximately $5.0 million. As measured by heating degree days, 2014 was 5.3% colder than 2013 and 15.4% colder than normal.

2013 vs. 2012: Our total retail gas margin increased by $16.2 million, or approximately 11.6%, when compared to 2012. We estimate that colder winter weather increased gas margins by approximately $22.1 million. As measured by heating degree days, 2013 was 26.8% colder than 2012 and 9.9% colder than normal. Gas margins were reduced by $8.1 million because of lower gas rates that became effective January 1, 2013.

Other Operation and Maintenance Expense

2014 vs. 2013: Our other operation and maintenance expense decreased by $60.9 million, or approximately 4.3%, when compared to 2013. This decrease was primarily driven by lower benefit costs related to pensions and medical costs.

Our operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages and amortization of regulatory assets.



	41	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

2013 vs. 2012: Our other operation and maintenance expense increased by $89.5 million, or approximately 6.7%, when compared to 2012. This increase was primarily driven by the reinstatement of $148.0 million of regulatory amortizations, offset in part by continued cost control efforts. For additional information on the regulatory amortizations, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- 2012 Wisconsin Rate Case.

Depreciation and Amortization Expense

2014 vs. 2013: Depreciation and Amortization expense increased by $17.1 million, or approximately 6.1%, when compared to 2013. This increase was primarily because of an overall increase in utility plant in service as a result of the biomass plant that went into service in November 2013. For additional information on the biomass facility, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Renewables, Efficiency, and Conservation.

2013 vs. 2012: Depreciation and Amortization expense increased by $21.0 million, or approximately 8.2%, when compared to 2012. This increase was primarily because of an overall increase in utility plant in service. In addition to the biomass facility that went into service in November 2013, the emission control equipment for units 5 and 6 of the Oak Creek Air Quality Control System (AQCS) project went into service in March 2012, and for units 7 and 8 in September 2012.

Treasury Grant

During 2014, we recognized $17.4 million of income related to a Treasury Grant associated with the completion of the biomass plant, compared to $48.0 million in 2013. The lower grant income corresponds to the lower bill credits provided to our retail electric customers in Wisconsin in 2014. For additional information on the Treasury Grant, see Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments.

Other Income and Deductions, net



Other Income and Deductions, net	2014		2013			2012
	(Millions of Dollars)

AFUDC - Equity	$	4.4	$	17.6		$	34.9
Gain on Property Sales	4.3		0.8			0.3
Other, net	—		(1.0		)	(2.9		)
Total Other Income and Deductions, net	$	8.7	$	17.4		$	32.3

2014 vs. 2013: Other income and deductions, net decreased by approximately $8.7 million, or 50.0%, when compared to 2013. This decrease primarily relates to lower AFUDC - Equity related to the biomass plant going into service in November 2013, partially offset by an increased gain on property sales.

2013 vs. 2012: Other income and deductions, net decreased by approximately $14.9 million, or 46.1%, when compared to 2012. This decrease primarily relates to lower AFUDC - Equity related to the Oak Creek AQCS project which emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8, partially offset by the biomass plant which went into service in November 2013.



	42	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

Interest Expense, net



Interest Expense, net	2014		2013		2012
	(Millions of Dollars)

Gross Interest Costs	$	118.3	$	128.8	$	127.7
Less: Capitalized Interest	1.8		7.4		14.5
Interest Expense, net	$	116.5	$	121.4	$	113.2

2014 vs. 2013: Our net interest expense decreased by $4.9 million, or 4.0%, as compared to 2013 primarily because of lower average interest rates on long-term debt. Our capitalized interest decreased by $5.6 million primarily because of lower construction work in progress as the biomass plant went into service in November 2013.

2013 vs. 2012: Our net interest expense increased by $8.2 million, or 7.2%, as compared to 2012, primarily because of lower capitalized interest. Our capitalized interest decreased by $7.1 million primarily because of lower construction work in progress.

Income Tax Expense

2014 vs. 2013: Our effective tax rate was 37.1% in 2014 compared with 35.7% in 2013. This increase in our effective tax rate was due to reduced tax benefits associated with Treasury Grant income and decreased AFUDC - Equity. For further information, see Note G -- Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2015 annual effective tax rate to be between 36.0% and 37.0%.

2013 vs. 2012: Our effective tax rate was 35.7% in 2013 compared with 34.4% in 2012. This increase in our effective tax rate was primarily the result of reduced domestic production activities deductions and AFUDC - Equity.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2014, 2013 and 2012:



	2014			2013			2012
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	862.8		$	862.6		$	807.0
Investing Activities	$	(567.5	)	$	(560.1	)	$	(605.6	)
Financing Activities	$	(296.4	)	$	(311.5	)	$	(180.0	)

Operating Activities

2014 vs. 2013: Cash provided by operating activities was $862.8 million during 2014, which was an increase of $0.2 million over 2013. The increase was related to higher net income, non-cash charges related to depreciation expense, and favorable cash flows from accounts receivable, primarily because of the timing of the Treasury Grant. Partially offsetting these favorable items were increases in working capital related to natural gas in storage and increases in regulatory assets.

2013 vs. 2012: Cash provided by operating activities was $862.6 million during 2013, which was an increase of $55.6 million over 2012. The increase is primarily because of lower contributions to our qualified benefit plans and higher non-cash charges to earnings. During 2013, we made no contributions to our qualified benefit plans, compared to contributions of $92.9 million during 2012. In addition, we had higher depreciation expense and amortization expense. Included in the higher amortization expense is a $120.9 million increase in the amortization



	43	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

of regulatory items. Partially offsetting these items is an increase in accounts receivable and accrued revenues of $201.3 million because of colder winter weather and the Treasury Grant.

Investing Activities

2014 vs. 2013: Cash used in investing activities was $567.5 million during 2014, which was $7.4 million higher than 2013. Our capital expenditures increased by $34.0 million during 2014 as compared to 2013, primarily because of starting the conversion of the fuel source for VAPP from coal to natural gas. Partially offsetting this increase is a decrease in cost of removal, net of salvage of $11.1 million and a decrease in customer advances for construction projects.

2013 vs. 2012: Cash used in investing activities was $560.1 million during 2013, which was $45.5 million lower than 2012. Our capital expenditures decreased by $68.9 million during 2013 as compared to 2012, primarily because of decreased spending as the Oak Creek AQCS project went into service in 2012. Our change in restricted cash decreased by $40.1 million which is related to the 2012 release of restricted cash through bill credits and the reimbursement of costs associated with the proceeds we received from the settlement with the DOE.

Financing Activities

The following table summarizes our cash flows from financing activities:



	2014			2013			2012
	(Millions of Dollars)

Dividends to Wisconsin Energy	$	(390.0	)	$	(340.0	)	$	(179.6	)
Net Increase in Debt	81.9			18.4			0.1
Other	11.7			10.1			(0.5		)
Cash Used in Financing	$	(296.4	)	$	(311.5	)	$	(180.0	)

2014 vs. 2013: Cash used in financing activities was $296.4 million during 2014 compared to $311.5 million during 2013. During 2014, we paid $50.0 million more in special dividends to Wisconsin Energy to balance our capital structure, which was more than offset by a $63.5 million increase in short-term debt.

2013 vs. 2012: Cash used in financing activities was $311.5 million during 2013 compared to $180.0 million during 2012. During 2013, we retired $300.0 million of long-term debt and issued $250 million of long-term debt. The net proceeds of the debt issuance were used to repay short-term debt and for other corporate purposes. In addition, we paid $160.4 million more dividends to Wisconsin Energy during 2013 as compared to 2012 which includes $100 million of special dividends to balance our capital structure.

CAPITAL RESOURCES AND REQUIREMENTS

Working Capital

As of December 31, 2014, our current liabilities exceeded our current assets by approximately $214.4 million. Included in our current liabilities is approximately $355.6 million of long-term debt and capital lease obligations due currently. We do not expect this to have any impact on our liquidity because we believe we have an adequate back-up line of credit in place for ongoing operations. We also have access to the capital markets to finance our construction program and to refinance current maturities of long-term debt if necessary.

Liquidity

We anticipate meeting our capital requirements 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.



	44	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

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

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

As of December 31, 2014, we had approximately $494.9 million of available, undrawn lines under our bank back-up credit facility. As of December 31, 2014, we had approximately $306.8 million of commercial paper outstanding that was supported by the available line of credit. During 2014, our maximum commercial paper outstanding was $401.0 million with a weighted-average interest rate of 0.22%. For additional information regarding our commercial paper balances during 2014, see Note K -- Short-Term Debt in the Notes to Consolidated Financial Statements.

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 December 31, 2014:



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

$500.0	$	5.1	$	494.9	December 2019

In December 2014, we amended our credit facility to extend the expiration from December 2017 to December 2019.

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

The following table shows our consolidated capitalization structure as of December 31:



Capitalization Structure	2014				2013
	(Millions of Dollars)

Common Equity	$	3,412.8	37.9	%	$	3,406.8	38.3	%
Preferred Stock	30.4		0.3	%	30.4		0.3	%
Long-Term Debt (a)	2,415.5		26.8	%	2,467.3		27.8	%
Capital Lease Obligations (a)	2,818.1		31.3	%	2,791.5		31.4	%
Short-Term Debt (b)	329.2		3.7	%	197.3		2.2	%
Total	$	9,006.0	100.0	%	$	8,893.3	100.0	%

(a) Includes current maturities
(b) Includes subsidiary note payable to Wisconsin Energy

For a summary of the interest rate, maturity and amount outstanding of each series of our long-term debt on a consolidated basis, see the Consolidated Statements of Capitalization.

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 December 31, 2014, the repurchased bonds were still outstanding, but were not reported as long-term debt or included on the Consolidated Statements of Capitalization 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.



	45	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

Bonus Depreciation Provisions

The Tax Increase Prevention Act of 2014 was signed into law on December 19, 2014, which extended the 50% bonus depreciation rules to include assets placed in service in 2014. As a result of the increased federal tax depreciation for 2014 and prior years, we did not make federal income tax payments for 2013 and 2014.

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at Standard & Poor's Ratings Services (S&P) and/or Baa3 at Moody's Investor Service (Moody's). As of December 31, 2014, we estimate that the collateral or the termination payments required under these agreements totaled approximately $195.3 million. Generally, collateral may be provided by a Wisconsin Energy guaranty, letter of credit or cash. We also have other commodity contracts that in the event of a credit rating downgrade could result in a reduction of our unsecured credit granted by counterparties.

In addition, 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 December 2014, Moody's affirmed our ratings (commercial paper, P-1; senior unsecured, A1) and our stable ratings outlook.

In August 2014, Fitch Ratings affirmed our ratings (commercial paper, F1; senior unsecured, A+) and our stable ratings outlook.

In June 2014, S&P affirmed our ratings (commercial paper, A-2; senior unsecured, A-) and our 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.

Capital Requirements

Capital Expenditures: Our estimated capital expenditures for the next three years are as follows:



	(Millions of Dollars)
2015	$	496.2
2016	472.7
2017	498.4
Total	$	1,467.3

The majority of spending consists of upgrading our electric and gas distribution systems. Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such as air quality standards, renewable energy standards and electric reliability initiatives that impact us.

Investments in Outside Trusts: We use outside trusts to fund our pension and certain other post-retirement obligations. These trusts had investments of approximately $1.4 billion as of December 31, 2014. These trusts hold investments that are subject to the volatility of the stock market and interest rates.

During 2014 and 2013, we made no contributions to our qualified pension plans or our qualified Other Post-Retirement Employee Benefit (OPEB) plans. In January 2015, we contributed $100 million to our qualified pension plans. Future contributions to the plans will be dependent upon many factors, including the performance of existing



	46	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

plan assets and long-term discount rates. For additional information, see Note N -- Benefits in the Notes to Consolidated Financial Statements.

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 that is material to our investors. For additional information, see Note F -- Variable Interest Entities in the Notes to Consolidated Financial Statements in this report.

Contractual Obligations/Commercial Commitments: We have the following contractual obligations and other commercial commitments as of December 31, 2014:



	Payments Due by Period
Contractual Obligations (a)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(Millions of Dollars)

Long-Term Debt Obligations (b)	$	4,571.6	$	362.4	$	193.1	$	686.5	$	3,329.6
Capital Lease Obligations (c)	9,775.3		439.2		880.0		851.6		7,604.5
Operating Lease Obligations (d)	38.1		5.2		7.1		4.3		21.5
Purchase Obligations (e)	11,251.3		796.5		1,169.7		966.3		8,318.8
Other Long-Term Liabilities	884.3		92.1		183.8		178.9		429.5
Total Contractual Obligations	$	26,520.6	$	1,695.4	$	2,433.7	$	2,687.6	$	19,703.9


(a)	The amounts included in the table are calculated using current market prices, forward curves and other estimates.


(b)	Principal and interest payments on Long-Term Debt (excluding capital lease obligations).


(c)	Capital Lease Obligations for power purchase commitments and the PTF leases.


(d)	Operating Lease Obligations for power purchase commitments and rail car leases.


(e)	Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation and for construction, information technology and other services for utility operations. This includes the power purchase agreement for Point Beach.

The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note G -- Income Taxes in the Notes to Consolidated Financial Statements in this report.

Our obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.

FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES

MARKET RISKS AND OTHER SIGNIFICANT RISKS

We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate. These risks, described in further detail below, include but are not limited to:

Regulatory Recovery: We account for our regulated operations in accordance with accounting guidance for regulated entities. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. Regulated entities are allowed to defer certain costs that would otherwise be charged to expense, if the regulated



	47	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. In general, regulatory assets are recovered in a period between one to eight years. Regulatory assets associated with pension and OPEB expenses are amortized as a component of pension and OPEB expense. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2014, our regulatory assets totaled $1,626.9 million and our regulatory liabilities totaled $615.9 million.

Commodity Prices: In the normal course of providing energy, we are subject to market fluctuations of the costs of coal, natural gas, purchased power and fuel oil used in the delivery of coal. We manage our fuel and gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas and fuel oil. In addition, we manage the risk of price volatility by utilizing gas and electric hedging programs.

Wisconsin's retail electric fuel cost adjustment procedure mitigates some of our risk of electric fuel cost fluctuation. The fuel rules allow for a deferral of prudently incurred fuel costs that fall outside of a symmetrical band (plus or minus 2%). Under the rules, any over or under-collection of fuel costs deferred at the end of the year would be incorporated into fuel cost recovery rates in future years. For information regarding the fuel rules, see Rates and Regulatory Matters -- Wisconsin Fuel Proceedings.

Natural Gas Costs: Higher natural gas costs could increase our working capital requirements and result in higher gross receipts taxes in the state of Wisconsin. Higher natural gas costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. Higher natural gas costs may also lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution.

As part of its December 2014 rate order, the PSCW authorized continued use of the escrow method of accounting for bad debt costs. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceeds or is less than amounts allowed in rates.

As a result of our GCRM, our gas utility operation receives dollar for dollar recovery on the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins. For information concerning our natural gas utility's GCRM, see Rates and Regulatory Matters.

Weather: Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Our electric revenues and sales are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. Our gas revenues and sales are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2014, 2013 and 2012, as measured by degree days, may be found above in Results of Operations.

Interest Rate: We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding as of December 31, 2014. Borrowing levels under these arrangements vary from period to period depending on capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels.

We performed an interest rate sensitivity analysis as of December 31, 2014 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2014, we had $306.8 million of commercial paper outstanding with a weighted-average interest rate of 0.25%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $3.1 million.

Marketable Securities Return: We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund



	48	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.

The fair value of our trust fund assets and expected long-term returns as of December 31, 2014 were approximately:



	As of December 31, 2014 (Millions of Dollars)		Expected Return on Assets in 2015

Pension trust funds	$	1,160.0	7.00	%
Other post-retirement benefits trust funds	$	224.9	7.25	%

Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

Wisconsin Energy consults with its investment advisors on an annual basis to help it forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.

Economic Conditions: Our service territory is within the state of Wisconsin and the Upper Peninsula of Michigan. We are exposed to market risks in the regional midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.

Inflation: We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Risk Factors in Item 1A.

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. The PTF units include PWGS 1, PWGS 2, Oak Creek expansion Unit 1 (OC 1) and Oak Creek expansion Unit 2 (OC 2).

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 are leasing the PTF units from We Power under long-term leases. We are recovering the lease payments associated with PWGS 1, PWGS 2, OC 1 and OC 2 in our rates as authorized by the PSCW, the MPSC and FERC.

We operate the PTF units and are authorized by the PSCW to fully recover prudently incurred operating and maintenance costs in our Wisconsin electric rates. As the operator of the units, we may request We Power make capital improvements to or further investments in the units. Under the lease terms, we would expect the costs of any



	49	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

capital improvements or further investments to be added to the lease payments, and ultimately to be recovered in our rates.

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 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. All warranty claims between the Company and Bechtel have now been resolved, none of which had a material impact on our financial statements.

RATES AND REGULATORY MATTERS

The PSCW regulates our retail electric, natural gas and steam rates in the state of Wisconsin, while FERC regulates our wholesale power, electric transmission and interstate gas transportation service rates. The MPSC regulates our retail electric rates in the state of Michigan. For the year ended December 31, 2014, we estimate that approximately 85% of our electric revenues were regulated by the PSCW, 2% were regulated by the MPSC and the balance of our electric revenues was regulated by FERC. In Wisconsin, a general rate case is typically filed every two years. All of our natural gas and steam revenues are regulated by the PSCW. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.

General Rate Proceedings

2015 Wisconsin Rate Case: In May 2014, we applied to the PSCW for a biennial review of costs and rates. On December 23, 2014, the PSCW approved the following rate adjustments:

•

A net bill increase related to non-fuel costs for our Wisconsin retail electric customers of approximately $2.7 million (0.1%) in 2015. This amount reflects receipt of SSR payments from MISO that are higher than anticipated when we filed our rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from the Treasury Grant we received in connection with the biomass facility. This $26.6 million is being returned to customers in the form of bill credits.


•	An electric rate increase for our Wisconsin retail electric customers of $26.6 million (0.9%) for 2016, related to the expiration of the bill credits provided to customers in 2015.


•	A rate decrease of $13.9 million (-0.5%) in 2015 related to a forecasted decrease in fuel costs. We will make an annual fuel cost filing, as required, for 2016.


•	A rate decrease of $10.7 million (-2.4%) for our natural gas customers in 2015, with no rate adjustment in 2016.


•	An increase of approximately $0.5 million (2.0%) for our downtown Milwaukee steam utility customers for 2015, with no rate adjustment in 2016.


•	An increase of approximately $1.2 million (7.3%) for our Milwaukee County steam utility customers for 2015, with no rate adjustment in 2016.

These rate adjustments were effective January 1, 2015. The electric rates reflect an increased allocation to fixed charges from 7.8% to 13.6% of total electric revenue requirements to more closely reflect our cost structure. In addition, our authorized return on equity was set at 10.2%. The PSCW also authorized the financial common equity component to remain the same at an average of 51%. The PSCW's order also allowed for escrow accounting treatment for SSR revenue from MISO.

In January 2015, certain parties appealed a portion of the PSCW's final decision adopting the Company's specific rate design changes, including new charges for customer owned generation within its service territory. We believe the appeal is without merit.

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.



	50	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K


•	An electric rate increase for our Wisconsin retail 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 reflected 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, our allowed return on equity remained at 10.4%. The PSCW also approved escrow accounting treatment for the Treasury Grant.

2012 Wisconsin Rate Case: In May 2011, we filed an application with the PSCW to initiate rate proceedings. In lieu of a traditional rate proceeding, we requested an alternative approach, which resulted in no increase in 2012 base rates for our customers. In order for us to proceed under this alternative approach, we requested that the PSCW issue an order that, among other things:


•	Authorized us to suspend the amortization of $148 million of regulatory costs during 2012, with amortization to begin again in 2013.


•	Authorized $148 million of carrying costs and depreciation on previously approved air quality and renewable energy projects, effective January 1, 2012.


•	Authorized the refund of $26 million of net proceeds from our settlement of the spent nuclear fuel litigation with the DOE.

We received a final written order from the PSCW in November 2011.

2012 and 2010 Michigan Rate Cases: In July 2011, we filed a $17.5 million rate increase request with the MPSC, primarily to recover the costs of environmental upgrades and OC 2. Pursuant to Michigan law, we self-implemented a $5.7 million interim electric base rate increase in January 2012. This increase was partially offset by a refund of $2.7 million of net proceeds from our settlement of the spent nuclear fuel litigation with the DOE, resulting in a net $3.0 million rate increase. In addition, approximately $2.0 million of renewable costs were included in our Michigan fuel recovery rate effective January 1, 2012. The MPSC approved a total increase in electric base rates of $9.2 million annually, effective June 27, 2012, and authorized a 10.1% return on equity.

In July 2009, we filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. In July 2010, the MPSC issued its final order, approving a total increase of $23.5 million annually, or 14.2%. In August 2010, our largest customers, two iron ore mines, filed an appeal with the MPSC regarding this rate order. In October 2010, the MPSC ruled on the mines' appeal and reduced the rate increase by approximately $0.3 million annually. In November 2010, the mines filed a Claim of Appeal of the October 2010 order with the Michigan Court of Appeals. In May 2014, the Court of Appeals issued its decision affirming the MPSC orders in both the 2010 and 2012 rate cases. In August 2014, the mines filed an Application for Leave to Appeal with the Michigan Supreme Court, which Application was denied on February 3, 2015.

Michigan SSR Proceeding: On February 10, 2015, the MPSC issued an Order and Notice of Hearing related to the ongoing operation of PIPP and the need for us to receive SSR payments with the return of the mines as our retail customers on February 1, 2015. We are unable to predict the resolution of this matter at this time.

For additional information relating to the SSR payments we are receiving, see Industry Restructuring and Competition below.

Wisconsin Fuel Proceedings

Embedded within our electric rates is an amount to recover fuel costs. The Wisconsin retail fuel rules require the Company to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the utility's symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the utility's approved fuel cost plan. The deferred fuel costs are subject to an excess revenues test.



	51	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

Other Rate Matters

Electric Transmission Cost Recovery: We divested our transmission assets with the formation of ATC in January 2001. We procure transmission service from ATC at FERC approved tariff rates. In connection with the formation of ATC, our transmission costs escalated due to the allocation of costs over ATC's footprint and increased transmission infrastructure requirements in Wisconsin. In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed us to use escrow accounting whereby we deferred transmission costs that exceeded amounts embedded in our rates. We were allowed to earn a return on the unrecovered transmission costs at our weighted-average cost of capital. Our 2008 and 2010 PSCW rate orders discontinued escrow accounting for prospective transmission charges and provided for recovery of those costs as incurred. In our 2013 Wisconsin rate case, the PSCW reauthorized escrow accounting for future transmission costs whereby we defer prospective costs that exceed amounts in rates, and we are allowed to earn a return on the incremental unrecovered transmission costs at the short-term debt rate. As of December 31, 2014, we had $32 million of unrecovered transmission costs related to deferrals subsequent to 2012 that earn a return at the short-term debt rate. In addition, as of December 31, 2014, we had $114 million of unrecovered transmission costs related to deferrals prior to 2008 that earn a return at the weighted-average cost of capital. In our 2015 Wisconsin rate case, the PSCW order reaffirmed our deferral of transmission costs.

Gas Cost Recovery Mechanism: Our natural gas operations operate under a GCRM as approved by the PSCW. Generally, the GCRM allows for a dollar for dollar recovery of gas costs. The GCRM uses a modified one for one method that measures commodity purchase costs against a monthly benchmark which includes a 2% tolerance. Costs in excess of this monthly benchmark are subject to additional review by the PSCW before they can be passed through to our customers.

Renewables, Efficiency and Conservation: In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. A utility's renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Our baseline renewable energy percentage is 2.27%. Under Act 141, we were required to increase our renewable energy percentage at least two percentage points to a level of 4.27% for the years 2010-2014. As of December 31, 2014, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. To comply with increasing requirements, we have constructed and contracted for several hundred megawatts of wind generation and 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 the plant also supports Domtar's sustainable papermaking operations. The final cost of completing this project was $268.9 million, excluding AFUDC. We also own four wind sites, consisting of 200 turbines with an installed capacity of 338 MW and a dependable capability of 66 MW.

We expect to be in compliance with Act 141's 2015 standard, and have entered into agreements for renewable energy credits which should allow us to remain in compliance with Act 141 through 2022. If market conditions are favorable, we may purchase more renewable energy credits.

Act 141 allows the PSCW to delay a utility's implementation of the renewable portfolio standard if it finds that achieving the renewable requirement would result in unreasonable rate increases or would lessen reliability, or that new renewable projects could not be permitted on a timely basis or could not be served by adequate transmission facilities. Act 141 provides that if a utility is in compliance with the renewable energy and energy efficiency requirements as determined by the PSCW, then the utility may not be ordered to achieve additional energy conservation or efficiency.

Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the Wisconsin Department of Administration back to the PSCW and/or contracted third parties. In addition, Act 141 required that 1.2% of utilities' annual operating revenues be used to fund these programs in 2014. The funding required by Act 141 for 2015 is also 1.2% of annual operating revenues.



	52	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

ELECTRIC SYSTEM RELIABILITY

We continue to upgrade our electric distribution system, including substations, transformers and lines. We had adequate capacity to meet the MISO calculated planning reserve margin during 2014 and 2013. All of our generating plants performed as expected during the warmest periods of the summer and all power purchase commitments under firm contract were received. During this period, public appeals for conservation were not required and we did not interrupt or curtail service to non-firm customers who participate in load management programs. We expect to have adequate capacity to meet the planning reserve margin requirements during 2015. However, extremely hot weather, unexpected equipment failure or unavailability across the 15-state MISO market footprint could require us to call upon load management procedures.

ENVIRONMENTAL MATTERS

Overview

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include but are not limited to current and future regulation of: (1) air emissions such as SO₂, NO_x, fine particulates, mercury and greenhouse gases; (2) water discharges; (3) disposal of coal combustion by-products such as fly ash; and (4) remediation of impacted properties, including former manufactured gas plant sites.

We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including: (1) the development of additional sources of renewable electric energy supply; (2) the review of water quality matters such as discharge limits and cooling water requirements and implementing improvements to our cooling water intake systems as needed; (3) the addition of emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules; (4) the conversion of the fuel source for VAPP from coal to natural gas; (5) the beneficial use of ash and other solid products from coal-fired generating units; and (6) the clean-up of former manufactured gas plant sites.

Air Quality

EPA - Consent Decree: In April 2003, we reached a Consent Decree with the EPA, in which we agreed to significantly reduce air emissions from our coal-fired generating facilities. In July 2003, the Consent Decree was amended to include the state of Michigan, and in October 2007, the U.S. District Court for the Eastern District of Wisconsin approved and entered the amended Consent Decree. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS that began service in 2012. In September 2014, the Consent Decree was amended a third time to update some provisions related to the conversion of VAPP from coal to natural gas. In order to achieve the reductions agreed to in the Consent Decree, over the past 11 years we have installed new pollution control equipment, including the Oak Creek AQCS, upgraded existing equipment and retired certain older coal units at a cost of approximately $1.2 billion. We do not expect future costs to have a material impact on our consolidated financial statements.

NAAQS

8-hour Ozone Standards: In 2008, the EPA issued a more stringent 8-hour ozone standard, and made final attainment designations for this revised standard in 2012. Sheboygan County and the eastern portion of Kenosha County were designated as non-attainment areas. As a result, 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 not 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.



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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

In April 2014, the U.S. District Court for the Northern District of California adopted a petition from environmental groups to require the EPA to propose a new ozone standard by 2014, and to finalize the standard by October 2015. On November 25, 2014, the EPA proposed to lower the 8-hour ozone standard from its current level of 75 parts per billion. As part of its proposal, the EPA requested comment on values from 60-70 parts per billion. 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.

Fine Particulate Standard: In 2009, the EPA designated three counties in southeast Wisconsin (Milwaukee, Waukesha and Racine) as not meeting the daily standard for PM_2.5. In April 2012, the EPA proposed to determine that these three counties meet the PM_2.5 standard, and proposed to suspend the requirement that the state submit a State Implementation Plan (SIP) including reasonably available control technology regulations. In February 2014, the EPA re-proposed this determination, and in April 2014, the EPA took action to redesignate the three counties to attainment. Our generating facilities in the counties are now subject to less stringent construction permitting requirements and emission offset provisions are no longer required for modifications to these facilities. In addition, in December 2012, the EPA issued a revised and more stringent annual PM_2.5standard. On December 18, 2014, the EPA determined that all areas of Wisconsin and Michigan's Upper Peninsula meet the revised standard and designated them as attainment areas. Therefore, we do not currently expect the lower standard to impose any additional requirements on our operations.

Sulfur Dioxide Standard: The EPA issued a new 1-Hour SO₂ NAAQS that became effective in August 2010. This standard represents a significant change 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. In May 2014, the EPA 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 that 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.

Nitrogen Dioxide Standard: In January 2010, the EPA announced a new hourly Nitrogen Dioxide standard, which became effective in April 2010. In February 2012, all areas of Wisconsin and Michigan were designated as unclassifiable. Until these areas are classified as attainment or non-attainment and any potential rules are adopted, we are unable to predict the impact on the operation of our generation facilities.

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 MDEQ.

In addition, both Wisconsin and Michigan have mercury rules that require a 90% reduction of mercury, and compliance with those rules will no longer be required after the compliance date for MATS.

In January 2013, the EPA issued the National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Industrial Boiler MACT Rule). The Industrial



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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

Boiler MACT rule imposes stringent limitations on numerous hazardous air pollutants from large boilers that do not meet the definition of electric generating units. The compliance date set forth in the rule is January 31, 2016, but a one year extension of that deadline may be available where emission controls cannot be installed and operational by the compliance date. Along with some smaller gas fired boilers in our fleet, the three coal fired boilers at the Milwaukee County Power Plant are subject to this rule. We are currently evaluating compliance options for these boilers.

Cross-State Air Pollution Rule: In August 2011, the EPA issued CSAPR, formerly known as the Clean Air Transport Rule. This rule was proposed 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 NO_x and SO₂ that contribute to PM_2.5 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. Briefing on further challenges to the rule allowed by the U.S. Supreme Court decision is ongoing. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision that cleared the way for the EPA to begin implementing CSAPR on January 1, 2015. We expect that there will be sufficient allowances available 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. In light of these developments, we withdrew our challenge to CSAPR.

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 PM_2.5 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 Michigan's regional haze 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. We believe we are well positioned to meet the requirements of the Clean Air Visibility rule based on air quality control system additions that are already in place or planned for our generating facilities.

Climate Change: We continue to take measures to reduce our emissions of GHG. We support flexible, market-based strategies to curb GHG emissions, including emissions trading, emission offset projects and credit for early actions. We support an approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters. We, along with our affiliates, have taken, and continue to take, several steps to reduce our emissions of GHG, including:


•	Repowered the Port Washington Power Plant from coal to natural gas-fired combined cycle units.


•	Added coal-fired units as part of the Oak Creek expansion that are the most thermally efficient coal units in our system.


•	Increased our investment in energy efficiency and conservation.


•	Added renewable capacity.


•	Converting the fuel source at the VAPP from coal to natural gas, scheduled for completion in 2015.


•	Retired coal units 1-4 at PIPP.

Federal, state, regional and international authorities have undertaken efforts to limit GHG emissions. The regulation of GHG emissions continues to be a top priority for the President's administration.

In accordance with instructions from the President, the EPA is pursuing regulation of GHG emissions using its existing authority under the CAA. In September 2013, the EPA issued new proposed New Source Performance Standards 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. Based upon currently available



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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

technology and the emission limits in the proposed rule, we believe that this rule effectively prohibits new conventional coal-fired power plants.

In addition, the EPA issued proposed guidelines relating to GHG emissions from existing generating units in June 2014, and has announced plans to issue final rules by mid-summer 2015. The EPA also published proposed performance standards for modified and reconstructed generating units. The proposed guidelines for existing fossil generating units 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 interim goal 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, 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 BART 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.

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2013, we reported CO₂ equivalent emissions of approximately 21.9 million metric tonnes to the EPA, compared with approximately 18.1 million metric tonnes for 2012. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 23.3 million metric tonnes to the EPA for 2014. The level of CO₂ and other greenhouse gas emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed and how our units are dispatched by MISO.

We are also required to report CO₂ equivalent amounts related to the natural gas our gas utility distributes and sells. For 2013, we reported approximately 4.1 million metric tonnes of CO₂ equivalent to the EPA related to our distribution and sale of natural gas, compared with approximately 3.3 million metric tonnes for 2012. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO₂emissions of approximately 4.4 million metric tonnes to the EPA for 2014.

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 received PSCW approval for this project in March 2014. Construction related to the conversion of the first two boilers was completed in November 2014, and the remaining two boilers are scheduled for completion in 2015.

For further information, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.

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. The EPA issued a final Phase II rule that became effective on October 14, 2014. The new rule applies to all of our existing generating facilities with



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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the Phase I rules.

The new Phase II 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. During 2015 and 2016, we plan to install fish protection screens at VAPP that 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. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our proposed intake modification at VAPP. We cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new requirements for our other generating facilities.

The WDNR issued a new Wisconsin Pollutant Discharge Elimination System (WPDES) permit for VAPP that became effective on January 1, 2013 that contains several additional requirements. Effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges all took effect immediately. Longer term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning and a compliance schedule for the installation of the new cooling water intake fish protection screens.

On November 10, 2014, the WDNR reissued the WPDES permit for the PSGS. We believe that the WDNR imposed unreasonable permit conditions with respect to temperature monitoring, the control of water treatment additive and phosphorus discharges.

To address these permit conditions, we filed a petition for a contested case hearing with the WDNR on January 9, 2015. On the same day, we also filed a request to be covered by the statewide phosphorus variance to address one of our concerns with the permit. We are working with the WDNR to determine if settlement is possible. A decision on the phosphorus variance request is pending.

Steam Electric Effluent Guidelines: These guidelines regulate waste water discharges from our power plant processes. In June 2013, the EPA issued a proposed rule for comment to modify these guidelines. We submitted comments primarily addressing potential effects to our wastewater treatment facilities and coal combustion residuals effluent management activities. The rules are expected to be finalized by September 2015. After promulgation of the final rules, the WDNR and MDEQ will need to modify state rules accordingly and then incorporate new requirements into our facility permits. The rule compliance deadline is as soon as possible after July 1, 2017 with full compliance expected by July 1, 2022. We already meet many of the proposed requirements defined by the EPA, and as a result believe we will be well positioned to comply with the proposed guidelines. There are several available options outlined in the proposed rule. The amount of additional costs we may need to incur to comply with the new guidelines, if any, will depend on which option(s) the EPA selects to incorporate into the final guidelines. Until the rules are finalized, we are unable to determine the impact on our facilities.

Land Quality

New Coal Combustion Products Regulation: We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Both Wisconsin and Michigan have regulations governing the use and disposal of these materials. In 2010, the EPA issued draft rules for public comment proposing two alternative rules for regulating coal combustion products, one of which would classify the materials as hazardous waste. The EPA issued the final rule on December 22, 2014, under which coal combustion residuals will be regulated as a non-hazardous waste. The rule is self-implementing which means that affected facilities must comply with the rules regardless of whether a state adopts the rule. We have been meeting the state requirements and have plans in place to implement the additional federal rule requirements.



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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

In the preamble to the final rule, the EPA referenced reports it received with respect to the molybdenum concerns raised in southeastern Wisconsin, and indicated it will continue to evaluate the beneficial use of coal ash in unencapsulated construction.

Manufactured Gas Plant Sites: We continue to voluntarily review and address environmental conditions at a number of former manufactured gas plant sites. For further information, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.

Ash Landfill Sites: We seek environmentally acceptable, beneficial uses for our combustion byproducts. For further information, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.

LEGAL MATTERS

Stray Voltage: On July 11, 1996, the PSCW issued a final order regarding the stray voltage policies of Wisconsin's investor-owned utilities. The order clarified the definition of stray voltage, affirmed the level at which utility action is required, and placed some of the responsibility for this issue in the hands of the customer. Additionally, the order established a uniform stray voltage tariff which delineates utility responsibility and provides for the recovery of costs associated with unnecessary customer demanded services.

Dairy farmers have made claims against us for loss of milk production and other damages to livestock allegedly caused by stray voltage and ground currents resulting from the operation of our electrical system, even though that electrical system has been operated within the parameters of the PSCW's order. The Wisconsin Supreme Court has rejected the arguments that, if a utility company's measurement of stray voltage is below the PSCW "level of concern," that utility could not be found negligent in stray voltage cases. Additionally, the Court has held that the PSCW regulations regarding stray voltage were only minimum standards to be considered by a jury in stray voltage litigation. As a result of these rulings, claims by dairy farmers for livestock damage have been based upon ground currents with levels measuring less than the PSCW "level of concern." We continue to evaluate various options and strategies to mitigate this risk.

On September 9, 2014, a new stray voltage case was filed against Wisconsin Electric in Sheboygan County, Wisconsin. We do not believe this lawsuit has any merit and intend to defend the case vigorously. This lawsuit is not expected to have a material adverse effect on our financial statements.

INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

The regulated energy industry continues to experience significant changes. FERC continues to support large RTOs, which affects the structure of the wholesale market. To this end, MISO implemented the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. The MISO Energy Markets commenced operation in April 2005 for energy distribution and in January 2009 for operating reserves. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when retail access might be implemented, if at all, in Wisconsin; however, Michigan has adopted retail choice.

Restructuring in Wisconsin: Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW has been focused on electric reliability infrastructure issues for the state of Wisconsin in recent years. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date.

Michigan Business

Michigan Settlement: On January 12, 2015, we, along with Wisconsin Energy, entered into an agreement with the Governor of the State of Michigan, the Attorney General of the State of Michigan, the Staff of the MPSC, and Tilden



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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

Mining Company and Empire Iron Mining Partnership, owners of the two mines in the Upper Peninsula of Michigan, to resolve all objections these parties raised at the FERC and the MPSC related to Wisconsin Energy’s proposed acquisition of Integrys. The agreement forms the basis for a settlement agreement between the parties and includes the following provisions which directly impact us:


•	The Governor, the Attorney General and the owners of the mines will each file a letter with FERC stating that they do not have any objection to FERC’s approval of Wisconsin Energy's acquisition of Integrys, and will refrain from taking any action at FERC seeking to oppose, otherwise condition or delay consummation of the transaction. These letters have been filed with FERC.

•

The settlement agreement will request that the MPSC order approve Wisconsin Energy's acquisition of Integrys subject to the following conditions: (i) the closing of the sale of our Michigan electric distribution assets and PIPP to Upper Peninsula Power Company (UPPCO) contemporaneously with the closing of the acquisition of Integrys; (ii) the closing of the sale of Wisconsin Public Service Corporation’s Michigan electric distribution assets to UPPCO contemporaneously with the closing of the acquisition; and (iii) termination of the PIPP SSR agreement between MISO and us no later than the closing date of the acquisition. To this end, we have entered into a non-binding term sheet to sell these assets to UPPCO, which is described in more detail below. The Attorney General, the MPSC Staff and the owners of the mines will not seek or support any other conditions on granting of MPSC approval of our acquisition of Integrys. Wisconsin Public Service Corporation is a subsidiary of Integrys.

The settlement agreements entered into by these parties, as well as two other intervenors, in the MPSC proceedings, were filed with the MPSC on January 30, 2015.

SSR Payments: 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.

In August 2013, the mines, which were served on an interruptible tariff, notified us that they intended to switch to an alternative electric supplier. In September 2013, the switch was made. In addition, other smaller retail customers have switched to an alternative electric supplier. Following that decision, we initiated discussions with MISO to compensate us for the continued short-term operation of the plant through 2014.

In August 2013, we filed a request with MISO to suspend the operation of all five units at PIPP. In October 2013, MISO informed us that the operation of all units is necessary to maintain reliability in the Upper Peninsula of Michigan.

In January 2014, we entered into an SSR agreement (Suspension) with MISO to recover costs for operating and maintaining the units. The agreement was effective February 1, 2014, had a one year term, and specified monthly payments to us of $4.4 million to cover fixed costs. The agreement also provided for the payment of our variable costs to operate and maintain the plant. MISO filed the SSR agreement with FERC, 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 of 2014 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 valid proposals by the March 3, 2014 deadline. Based upon our evaluation and the lack of interest to purchase the plant, in April 2014, we filed a request with MISO to retire PIPP effective October 15, 2014. In May 2014, MISO informed us that they had determined the operation of all five units at PIPP was necessary for reliability purposes; therefore, the units would continue to be designated as SSR units.

We entered into a new SSR agreement (Retirement) with MISO, effective October 15, 2014, that covered the operating costs of PIPP through December 2015. The new SSR agreement also included, among other things, costs to comply with the MATS rule 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 were approximately $8.1 million. On November 10, 2014, FERC accepted the new SSR agreement, but it is subject to further action.

MISO is responsible for allocating the SSR costs to various market participants within the MISO footprint consistent with FERC approved tariffs. Several interested parties, including the PSCW and the MPSC, have filed complaints



	59	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

with the FERC regarding the allocation among the different jurisdictions of the SSR costs associated with the continued operation of PIPP. On February 19, 2015, FERC acted on the jurisdictional allocation of the SSR costs, reaffirming that it is unjust and unreasonable to allocate SSR costs pro rata to all market participants and that SSR costs must be allocated to the load-serving entities that require the operation of SSR units for reliability purposes. FERC directed MISO to file a new study method to identify the entities that benefit from the operation of SSR units within 60 days of the decision date and to allocate the costs directly to these entities.

On February 17, 2015, we entered into an agreement with the owners of the two iron ore mines whereby we agreed to request termination of the SSR agreement effective February 1, 2015, and the two mines agreed to remain full requirements customers until the earlier of the sale of PIPP and July 31, 2015. On the same date, we requested MISO to terminate the SSR agreement, and on February 18, 2015, MISO filed a request with FERC to have the SSR terminated effective February 1, 2015. We do not expect the termination of the SSR agreement to have a material impact on our financial condition or results of operations.

Effective February 1, 2015, the mines returned as retail customers. We expect to defer the net revenue from those sales and will apply these amounts for the benefit of Wisconsin retail electric customers in future rate proceedings. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice.

Sale of Michigan Assets: In January 2015, we entered into a non-binding term sheet to sell our Michigan electric distribution assets and PIPP to UPPCO. We currently expect to enter into a definitive agreement by the end of March 2015. The ultimate sale of these assets would have to be approved by several state and federal regulatory bodies, including the MPSC, PSCW and FERC. If the sale is consummated on terms commensurate with the non-binding term sheet, consistent with the treatment that would be applied to a generating unit retirement we will seek recovery of approximately $190 million of net unrecovered plant costs.

We believe that the sale of these assets is in the best interest of our customers because of the costs associated with the next best solution, which includes operating PIPP for at least five more years. These costs would include ongoing operating costs, decommissioning and dismantling costs and any increased costs for additional transmission capacity in the Upper Peninsula.

Electric Transmission, Capacity and Energy Markets

In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which includes the bid-based energy markets and an ancillary services market. We previously self-provided both regulation reserves and contingency reserves. In the MISO ancillary services market, we buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market has been able to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

In MISO, base transmission costs are currently being paid by Load Serving Entities located in the service territories of each MISO transmission owner. FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.

We, along with others, have sought rehearing and/or appeal of the FERC's various Revenue Sufficiency Guarantee orders related to the determination that MISO had applied its energy markets tariff correctly in the assessment of the charges. The net effects of any final determination by FERC or the courts are uncertain at this time.

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



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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

Beginning June 1, 2013, MISO instituted an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources could be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. Our capacity requirements during 2014 were fulfilled using our own capacity resources.

Natural Gas Utility Industry

Restructuring in Wisconsin: The PSCW previously instituted generic proceedings to consider how its regulation of gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer segments with workably competitive market choices and has adopted standards for transactions between a utility and its gas marketing affiliates. However, work on deregulation of the gas distribution industry by the PSCW continues to be on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.

OTHER MATTERS

Paris Generating Station Units 1 and 4 Temporary Outage: Between 2000 and 2002, we replaced the blades on the four PSGS combustion turbine generators with blades that were approximately 7% more efficient. 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; however, in January 2013, the WDNR indicated that it considered this maintenance to be a modification requiring a construction permit. This matter has since been settled. In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to Units 1 and 4, allowing those units to restart. We received an “after the fact” permit from the WDNR, and the Units are now available for service. On October 24, 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit.

In February 2013, the Sierra Club filed for a contested case hearing with the WDNR in connection with the administration order issued in this matter, which was granted. However, a hearing has not yet been scheduled.

ACCOUNTING DEVELOPMENTS

New Pronouncements: See Note B -- Recent Accounting Pronouncements in the Notes to Consolidated Financial Statements in this report for information on new accounting pronouncements.

Treasury Grant: In December 2013, we filed an application with the United States Treasury for a Treasury Grant related to the construction of our biomass facility, which was placed into service in November 2013. 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.

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 are being returned to customers in the form of bill credits.

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 recognized Treasury Grant income to match the bill credits related to the grant that our Wisconsin retail electric customers received.



	61	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

CRITICAL ACCOUNTING ESTIMATES

Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.

The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective or complex judgments:

Regulatory Accounting: We operate under rates established by state and federal regulatory commissions which are designed to recover the cost of service and provide a reasonable return to investors. The actions of our regulators may allow us to defer costs that non-regulated entities would expense and accrue liabilities that non-regulated companies would not. As of December 31, 2014, we had $1,626.9 million in regulatory assets and $615.9 million in regulatory liabilities. In the future, if we move to market based rates, or if the actions of our regulators change, we may conclude that we are unable to follow regulatory accounting. In this situation, we would record the regulatory assets related to unrecognized pension and OPEB costs as a reduction of equity, after tax. The balance of our regulatory assets net of regulatory liabilities would be recorded as an extraordinary after-tax non-cash charge to earnings. We continually review the applicability of regulatory accounting and have determined that it is currently appropriate to continue following it. In addition, each quarter we perform a review of our regulatory assets and our regulatory environment and we evaluate whether we believe that it is probable that we will recover the regulatory assets in future rates. See Note C -- Regulatory Assets and Liabilities in the Notes to Consolidated Financial Statements for additional information.

Pension and OPEB: Our reported costs of providing non-contributory defined pension benefits (described in Note N -- Benefits in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and the discount rates used in determining the projected benefit obligation and pension costs.

Changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.

The following table reflects pension plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.



Pension Plan	Impact on
Actuarial Assumption	Annual Cost
	(Millions of Dollars)

0.5% decrease in discount rate and lump sum conversion rate	$	5.0
0.5% decrease in expected rate of return on plan assets	$	5.5

In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note N -- Benefits in the Notes to Consolidated Financial Statements). Our reported costs of providing these post-retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee age and other demographics, our contributions to the plans, earnings on plan assets



	62	Wisconsin Electric Power Company



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)	2014 Form 10-K

and health care cost trends. Changes made to the provisions of the plans may also impact current and future OPEB costs. OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and the discount rates used in determining the OPEB and post-retirement costs. Our OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns, as well as changes in general interest rates, may result in increased or decreased other post-retirement costs in future periods. Similar to accounting for pension plans, our regulators have adopted accounting guidance for compensation related to retirement benefits for rate-making purposes.

The following table reflects OPEB plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.



OPEB Plan	Impact on
Actuarial Assumption	Annual Cost
	(Millions of Dollars)

0.5% decrease in discount rate	$	0.6
0.5% decrease in health care cost trend rate in all future years	$	(2.9	)
0.5% decrease in expected rate of return on plan assets	$	1.1

In October 2014, the Society of Actuaries released a new set of mortality tables (RP-2014) and an accompanying mortality improvement scale (MP-2014), which incorporates increasing life expectancy experience in the United States. Based on our initial review of the proposed tables, we believe our pension and OPEB obligations would increase by approximately 6% if we adopted these tables. We will continue to evaluate the mortality assumptions in the future, as necessary, to conform to our experience.

Unbilled Revenues: We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total operating revenues during 2014 of approximately $4.1 billion included accrued revenues of $223.1 million as of December 31, 2014.


ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See 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 Item 7 of this report, as well as Note L -- Derivative Instruments and Note M -- Fair Value Measurements in the Notes to Consolidated Financial Statements, for information concerning potential market risks to which we are exposed.



	63	Wisconsin Electric Power Company



	2014 Form 10-K


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
Year Ended December 31

	2014		2013		2012
	(Millions of Dollars)

Operating Revenues	$	4,059.4	$	3,800.2	$	3,613.3

Operating Expenses
Fuel and purchased power	1,228.1		1,158.1		1,103.8
Cost of gas sold	432.6		278.3		227.7
Other operation and maintenance	1,356.4		1,417.3		1,327.8
Depreciation and amortization	295.7		278.6		257.6
Property and revenue taxes	113.6		110.0		113.1
Total Operating Expenses	3,426.4		3,242.3		3,030.0

Treasury Grant	17.4		48.0		—

Operating Income	650.4		605.9		583.3

Equity in Earnings of Transmission Affiliate	57.9		60.2		57.6
Other Income and Deductions, net	8.7		17.4		32.3
Interest Expense, net	116.5		121.4		113.2

Income Before Income Taxes	600.5		562.1		560.0

Income Tax Expense	222.6		200.9		192.7

Net Income	377.9		361.2		367.3

Preferred Stock Dividend Requirement	1.2		1.2		1.2

Earnings Available for Common Stockholder	$	376.7	$	360.0	$	366.1

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



	64	Wisconsin Electric Power Company



	2014 Form 10-K



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31

ASSETS

	2014			2013
	(Millions of Dollars)
Property, Plant and Equipment
Electric	$	9,024.8		$	8,717.0
Gas	1,025.4			977.4
Steam	101.5			102.0
Common	339.6			307.4
Other	53.1			56.8
	10,544.4			10,160.6
Accumulated depreciation	(3,406.1		)	(3,258.8		)
	7,138.3			6,901.8
Construction work in progress	140.9			101.9
Leased facilities, net	2,215.0			2,279.0
Net Property, Plant and Equipment	9,494.2			9,282.7

Investments
Equity investment in transmission affiliate	372.9			354.1
Other	0.2			0.2
Total Investments	373.1			354.3

Current Assets
Cash and cash equivalents	24.0			25.1
Accounts receivable, net of allowance for
doubtful accounts of $46.8 and $39.7	265.3			335.7
Accounts receivable from related parties	8.1			9.1
Accrued revenues	223.1			240.7
Materials, supplies and inventories	320.5			281.0
Current deferred tax asset, net	46.7			75.8
Prepayments	139.5			137.7
Other	19.0			8.7
Total Current Assets	1,046.2			1,113.8

Deferred Charges and Other Assets
Regulatory assets	1,626.9			1,370.3
Other	106.3			164.5
Total Deferred Charges and Other Assets	1,733.2			1,534.8

Total Assets	$	12,646.7		$	12,285.6

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



	65	Wisconsin Electric Power Company



	2014 Form 10-K



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31

CAPITALIZATION AND LIABILITIES

	2014		2013
	(Millions of Dollars)
Capitalization
Common equity	$	3,412.8	$	3,406.8
Preferred stock	30.4		30.4
Long-term debt	2,165.5		2,167.3
Capital lease obligations	2,712.5		2,712.0
Total Capitalization	8,321.2		8,316.5

Current Liabilities
Long-term debt and capital lease obligations due currently	355.6		379.5
Short-term debt	306.8		174.5
Subsidiary note payable to Wisconsin Energy	22.4		22.8
Accounts payable	287.2		273.8
Accounts payable to related parties	87.8		85.9
Accrued payroll and benefits	87.1		89.3
Other	113.7		132.3
Total Current Liabilities	1,260.6		1,158.1

Deferred Credits and Other Liabilities
Regulatory liabilities	615.9		634.2
Deferred income taxes - long-term	1,963.9		1,794.5
Pension and other benefit obligations	254.5		160.1
Other	230.6		222.2
Total Deferred Credits and Other Liabilities	3,064.9		2,811.0

Commitments and Contingencies (Note Q)

Total Capitalization and Liabilities	$	12,646.7	$	12,285.6

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



	66	Wisconsin Electric Power Company



	2014 Form 10-K



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31

	2014			2013			2012
	(Millions of Dollars)
Operating Activities
Net income	$	377.9		$	361.2		$	367.3
Reconciliation to cash
Depreciation and amortization	303.4			288.3			263.6
Deferred income taxes and investment tax credits, net	191.4			193.6			194.1
Contributions to qualified benefit plans	—			—			(92.9		)
Change in - Accounts receivable and accrued revenues	91.0			(137.0		)	64.3
Inventories	(39.5		)	31.2			7.0
Other current assets	(8.7		)	0.7			6.9
Accounts payable	18.2			(29.4		)	41.4
Accrued income taxes, net	(7.5		)	23.6			89.4
Deferred costs, net	(15.1		)	(8.7		)	9.2
Other current liabilities	(21.7		)	21.8			(2.4		)
Other, net	(26.6		)	117.3			(140.9		)
Cash Provided by Operating Activities	862.8			862.6			807.0

Investing Activities
Capital expenditures	(540.9		)	(506.9		)	(575.8		)
Investment in transmission affiliate	(11.5		)	(9.2		)	(13.8		)
Change in restricted cash	—			2.7			42.8
Cost of removal, net of salvage	(20.9		)	(32.0		)	(32.9		)
Other, net	5.8			(14.7		)	(25.9		)
Cash Used in Investing Activities	(567.5		)	(560.1		)	(605.6		)

Financing Activities
Dividends paid on common stock	(390.0		)	(340.0		)	(179.6		)
Dividends paid on preferred stock	(1.2		)	(1.2		)	(1.2		)
Issuance of long-term debt	250.0			250.0			250.0
Retirement of long-term debt	(300.0		)	(300.0		)	—
Change in total short-term debt	131.9			68.4			(249.9		)
Other, net	12.9			11.3			0.7
Cash Used In Financing Activities	(296.4		)	(311.5		)	(180.0		)

Change in Cash and Cash Equivalents	(1.1		)	(9.0		)	21.4

Cash and Cash Equivalents at Beginning of Year	25.1			34.1			12.7

Cash and Cash Equivalents at End of Year	$	24.0		$	25.1		$	34.1

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



	67	Wisconsin Electric Power Company



	2014 Form 10-K



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31

		2014			2013
		(Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)
Common stock - $10 par value; authorized
65,000,000 shares; outstanding - 33,289,327 shares		$	332.9		$	332.9
Other paid in capital		984.4			965.1
Retained earnings		2,095.5			2,108.8
Total Common Equity		3,412.8			3,406.8

Preferred Stock (Note I)		30.4			30.4

Long-Term Debt
Debentures (unsecured)	6.00% due 2014	—			300.0
	6.25% due 2015	250.0			250.0
	1.70% due 2018	250.0			250.0
	4.25% due 2019	250.0			250.0
	2.95% due 2021	300.0			300.0
	6-1/2% due 2028	150.0			150.0
	5.625% due 2033	335.0			335.0
	5.70% due 2036	300.0			300.0
	3.65% due 2042	250.0			250.0
	4.25% due 2044	250.0			—
	6-7/8% due 2095	100.0			100.0

Note (secured, nonrecourse)	4.81% effective rate due 2030	2.0			2.0

Unamortized discount, net		(21.5		)	(19.7		)
Long-term debt due currently		(250.0		)	(300.0		)
Total Long-Term Debt		2,165.5			2,167.3

Obligations Under Capital Leases (see Note J)		2,712.5			2,712.0

Total Long-Term Capitalization		$	8,321.2		$	8,316.5

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



	68	Wisconsin Electric Power Company



	2014 Form 10-K



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON EQUITY

	Common		Other Paid		Retained
	Stock		In Capital		Earnings			Total
	(Millions of Dollars)

Balance - December 31, 2011	$	332.9	$	941.9	$	1,902.3		$	3,177.1
Net income					367.3			367.3
Cash dividends
Common stock					(179.6		)	(179.6		)
Preferred stock					(1.2		)	(1.2		)
Stock-based compensation			2.8					2.8
Tax benefit of exercised stock options allocated from Parent			—					—
Balance - December 31, 2012	332.9		944.7		2,088.8			3,366.4
Net income					361.2			361.2
Cash dividends
Common stock					(340.0		)	(340.0		)
Preferred stock					(1.2		)	(1.2		)
Stock-based compensation			3.7					3.7
Tax benefit of exercised stock options allocated from Parent			16.7					16.7
Balance - December 31, 2013	332.9		965.1		2,108.8			3,406.8
Net income					377.9			377.9
Cash dividends
Common stock					(390.0		)	(390.0		)
Preferred stock					(1.2		)	(1.2		)
Stock-based compensation			3.5					3.5
Tax benefit of exercised stock options allocated from Parent			15.8					15.8
Balance - December 31, 2014	$	332.9	$	984.4	$	2,095.5		$	3,412.8

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



	69	Wisconsin Electric Power Company



	2014 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General: Wisconsin Electric Power Company (Wisconsin Electric, the Company, our, us or we), a subsidiary of Wisconsin Energy, is an electric, gas and steam utility which services electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metropolitan Milwaukee, Wisconsin. We consolidate our wholly-owned subsidiary, Bostco. Bostco had total assets of $28.4 million and $29.1 million as of December 31, 2014 and 2013, respectively.

All intercompany transactions and balances have been eliminated from the consolidated financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenues: We recognize energy revenues on the accrual basis and include estimated amounts for services rendered but not billed.

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules in Wisconsin allow us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the approved fuel cost plan. The deferred under-collected amounts are subject to an excess revenues test.

Our retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs. We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.

Accounting for MISO Energy Transactions: The MISO Energy Markets operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour.

Other Income and Deductions, Net: We recorded the following items in Other Income and Deductions, net for the years ended December 31:



Other Income and Deductions, net	2014		2013			2012
	(Millions of Dollars)

AFUDC - Equity	$	4.4	$	17.6		$	34.9
Gain on Property Sales	4.3		0.8			0.3
Other, net	—		(1.0		)	(2.9		)
Total Other Income and Deductions, net	$	8.7	$	17.4		$	32.3

Property and Depreciation: We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes AFUDC - Equity. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.9% in 2014, 2013 and 2012.



	70	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment.

We collect in our rates amounts representing future removal costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $571.2 million as of December 31, 2014 and $558.9 million as of December 31, 2013.

Allowance For Funds Used During Construction: AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - Debt) used during plant construction, and a return on stockholders' capital (AFUDC - Equity) used for construction purposes. AFUDC - Debt is recorded as a reduction of interest expense and AFUDC - Equity is recorded in Other Income and Deductions, net.

We recorded the following AFUDC for the years ended December 31:



	2014		2013		2012
	(Millions of Dollars)

AFUDC - Debt	$	1.8	$	7.4	$	14.5
AFUDC - Equity	$	4.4	$	17.6	$	34.9

Materials, Supplies and Inventories: Our inventory as of December 31 consists of:



Materials, Supplies and Inventories	2014		2013
	(Millions of Dollars)

Fossil Fuel	$	125.5	$	117.5
Materials and Supplies	145.0		129.5
Natural Gas in Storage	50.0		34.0
Total	$	320.5	$	281.0

Substantially all fossil fuel, materials and supplies and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.

Regulatory Accounting: The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and expensed in the periods when they are reflected in rates. We defer regulatory assets pursuant to specific or generic orders issued by our regulators. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. In general, regulatory assets are recovered in a period between one to eight years. For further information, see Note C.

Asset Retirement Obligations: We record a liability for a legal ARO in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply regulatory accounting guidance and recognize regulatory assets or liabilities for the timing differences between when we recover legal AROs in rates and when we would recognize these costs. For further information, see Note E.

Derivative Financial Instruments: We have derivative physical and financial instruments which we report at fair value. For further information, see Note L.



	71	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

Cash and Cash Equivalents: Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.

Margin Accounts: Cash deposited in brokerage accounts for margin requirements is recorded in Other Current Assets on our Consolidated Balance Sheets.

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. We do not believe that these restrictions will materially affect our operations. For further information, see Note H.

Impairment or Disposal of Long Lived Assets: We carry property and equipment related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2014, we had no assets classified as Held for Sale. Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

Investments: We account for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 23.0% in ATC as of December 31, 2014 and 2013. We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note P.

Income Taxes: We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized.

Investment tax credits related to regulated utility assets are recorded as a deferred credit on the balance sheet and amortized to income over the applicable service lives of related properties in accordance with regulatory treatment.

We are included in Wisconsin Energy's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with Wisconsin Energy, we are allocated income tax payments and refunds based upon our separate tax computation. For further information on income taxes, see Note G.

Wisconsin Energy allocates the tax benefit of exercised stock options to us to the extent the option holder's payroll cost was incurred by us. We record the allocated tax benefit as an addition to paid in capital.

We recognize interest and penalties accrued related to unrecognized tax benefits in Income Taxes in our Consolidated Income Statements, as well as Regulatory Assets or Regulatory Liabilities in our Consolidated Balance Sheets.

We collect sales and use taxes from our customers and remit these taxes to governmental authorities. These taxes are recorded in our Consolidated Income Statements on a net basis.

Stock Options: Our employees participate in the Wisconsin Energy stock-based compensation plan. The amounts reported represent the allocated costs related to options held by our employees.

Wisconsin Energy estimates the fair value of stock options using the binomial pricing model. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than 10 years from the grant date. Excess tax benefits are reported as a financing cash inflow. In addition, Wisconsin Energy reports unearned stock-based compensation associated with non-vested



	72	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

restricted stock and performance awards within other paid in capital in its Consolidated Statements of Common Equity. For a discussion of the impacts to our Consolidated Financial Statements, see Note H.

The fair value of each Wisconsin Energy option was calculated using a binomial option pricing model using the following weighted-average assumptions:



	2014	2013	2012
Risk-free interest rate	0.1% - 3.0%	0.1% - 1.9%	0.1% - 2.0%
Dividend yield	3.8%	3.7%	3.9%
Expected volatility	18.0%	18.0%	19.0%
Expected life (years)	5.8	5.9	5.9
Expected forfeiture rate	2.0%	2.0%	2.0%
Weighted-average fair value
of stock options granted	$4.18	$3.45	$3.34

Treasury Grant: In December 2013, we filed an application with the United States Treasury for a Section 1603 renewable energy grant related to the construction of our biomass facility in Rothschild, Wisconsin. The PSCW anticipated the recognition of this grant as income when it set rates for the two years beginning January 1, 2013. We provided bill credits to our customers in 2013 and 2014. For the years ended December 31, 2014 and 2013, $17.4 million and $48.0 million, respectively, was recognized as income, which reflects the amount that was returned to customers in the form of bill credits during the year. The accounting reflects the regulatory treatment of the grant.

B -- RECENT 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.

C -- REGULATORY ASSETS AND LIABILITIES

Our primary regulator, the PSCW, considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon orders or correspondence with our regulators. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2014, we had $11.7 million of regulatory assets not earning a return and $115.1 million of regulatory assets earning a return based on short-term interest rates.

In December 2014, the PSCW issued a rate order effective January 1, 2015 that, among other things, reaffirmed our accounting for the regulatory assets and liabilities identified below.



	73	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

Our regulatory assets and liabilities as of December 31 consist of:



	2014		2013
	(Millions of Dollars)
Regulatory Assets
Deferred plant related -- capital leases	$	603.0	$	512.5
Deferred unrecognized pension costs	482.8		393.0
Deferred income tax related	171.5		165.8
Escrowed electric transmission costs	146.0		126.8
Other, net	223.6		172.2
Total regulatory assets	$	1,626.9	$	1,370.3

Regulatory Liabilities
Deferred cost of removal obligations	$	571.2	$	558.9
Other, net	44.7		75.3
Total regulatory liabilities	$	615.9	$	634.2

Our rates allow us to recover and expense capital lease payments as they are due. We defer as a regulatory asset the difference between the capital lease expense recovered in rates and the expense that would result from the amortization of the leased asset and the imputed interest expense.

D -- PROPOSED ACQUISITION OF INTEGRYS BY WISCONSIN ENERGY

On June 22, 2014, our parent company, Wisconsin Energy, entered into an agreement and plan of merger (Merger Agreement) 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. We expect Wisconsin Energy to finance the acquisition through the issuance of approximately 91 million shares of Wisconsin Energy common stock to Integrys shareholders and through the issuance of approximately $1.5 billion of debt. Wisconsin Energy will also assume all of Integrys' outstanding debt. The combined company will be named WEC Energy Group, Inc.

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 FERC, Federal Communications Commission, PSCW, Illinois Commerce Commission, MPSC and Minnesota Public Utilities Commission. The status of these matters as of December 31, 2014 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 15, 2014, Wisconsin Energy filed an application with the FERC. The initial public comment period closed on October 17, 2014. Wisconsin Energy subsequently submitted additional information to respond to FERC questions on December 18, 2014. That comment period is now closed.


•	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.

•

On November 21, 2014, the shareholders of Wisconsin Energy voted to approve the issuance of common stock as contemplated by the Merger Agreement, as well as to amend the restated articles of incorporation to change the name of Wisconsin Energy from Wisconsin Energy Corporation to WEC Energy Group, Inc. The shareholders of Integrys approved the adoption of the Merger Agreement at its shareholder meeting held on November 21, 2014.

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



	74	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

E -- ASSET RETIREMENT OBLIGATIONS

AROs have been recorded for asbestos abatement at certain generation and substation facilities, and for obligations associated with the removal and dismantlement of generation facilities. AROs are recorded in other long-term liabilities on the Consolidated Balance Sheets. The following table presents the change in our AROs during 2014 and 2013:



	2014			2013
	(Millions of Dollars)

Balance as of January 1	$	39.4		$	41.5
Liabilities Settled	(1.1		)	(4.3		)
Accretion	2.2			2.2
Balance as of December 31	$	40.5		$	39.4

F -- 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.

We have approximately $174.0 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under contracts considered variable interests in 2014, 2013 and 2012 were $53.0 million, $50.3 million and $45.8 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

G -- INCOME TAXES

The following table is a summary of income tax expense for each of the years ended December 31:



Income Taxes	2014			2013			2012
	(Millions of Dollars)

Current tax expense (benefit)	$	31.2		$	7.3		$	(1.4	)
Deferred income taxes, net	192.5			194.7			195.2
Investment tax credit, net	(1.1		)	(1.1		)	(1.1		)
Total Income Tax Expense	$	222.6		$	200.9		$	192.7



	75	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following:



	2014					2013					2012
				Effective					Effective					Effective
Income Tax Expense	Amount			Tax Rate		Amount			Tax Rate		Amount			Tax Rate
	(Millions of Dollars)

Expected tax at statutory federal tax rates	$	209.8		35.0	%	$	196.3		35.0	%	$	195.6		35.0	%
State income taxes net of federal tax benefit	33.0			5.5	%	31.7			5.6	%	28.8			5.1	%
Production tax credits	(17.4		)	(2.9	)%	(16.7		)	(3.0	)%	(15.9		)	(2.8	)%
Treasury Grant	(3.8		)	(0.6	)%	(7.4		)	(1.3	)%	—			—	%
AFUDC - Equity	(1.5		)	(0.2	)%	(6.1		)	(1.1	)%	(12.2		)	(2.2	)%
Investment tax credit restored	(1.1		)	(0.2	)%	(1.1		)	(0.2	)%	(1.1		)	(0.2	)%
Domestic production activities deduction	—			—	%	—			—	%	(12.6		)	(2.3	)%
Other, net	3.6			0.5	%	4.2			0.7	%	10.1			1.8	%
Total Income Tax Expense	$	222.6		37.1	%	$	200.9		35.7	%	$	192.7		34.4	%

The components of deferred income taxes classified as net current assets and net long-term liabilities as of December 31 are as follows:



Deferred Tax Assets	2014		2013
	(Millions of Dollars)
Current
Future federal tax benefits	$	56.0	$	113.1
Uncollectible account expense	15.6		17.2
Employee benefits and compensation	11.6		11.7
Recoverable gas costs	1.0		0.5
Other	2.3		3.3
Total Current Deferred Tax Assets	86.5		145.8

Non-current
Deferred revenues	221.3		237.0
Employee benefits and compensation	92.1		92.4
Construction advances	15.5		15.0
Emission Allowances	0.1		—
Other	31.7		42.2
Total Non-Current Deferred Tax Assets	360.7		386.6
Total Deferred Tax Assets	$	447.2	$	532.4



	76	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K



Deferred Tax Liabilities	2014		2013
	(Millions of Dollars)
Current
Prepaid items	$	39.8	$	70.0
Total Current Deferred Tax Liabilities	39.8		70.0

Non-current
Property-related	1,942.2		1,820.9
Investment in transmission affiliate	164.1		147.8
Employee benefits and compensation	131.2		135.0
Deferred transmission costs	58.5		50.8
Other	28.6		26.6
Total Non-current Deferred Tax Liabilities	2,324.6		2,181.1
Total Deferred Tax Liabilities	$	2,364.4	$	2,251.1

Consolidated Balance Sheet Presentation	2014		2013
Current Deferred Tax Asset	$	46.7	$	75.8
Non-Current Deferred Tax Liability	$	1,963.9	$	1,794.5

Consistent with rate-making treatment, deferred taxes are offset in the above table for temporary differences which have related regulatory assets or liabilities.

As of December 31, 2014, we had approximately $3.9 million and $54.6 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of approximately $1.4 million and $54.6 million, respectively. As of December 31, 2013, we had approximately $216.8 million and $37.2 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of approximately $75.9 million and $37.2 million, respectively. These net operating loss carryforwards begin to expire in 2030. We anticipate that we will have future taxable income sufficient to utilize these deferred tax assets.

We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



	2014			2013
	(Millions of Dollars)

Balance as of January 1	$	8.4		$	10.8
Reductions for tax positions of prior years	(1.2		)	(2.4		)
Balance as of December 31	$	7.2		$	8.4

The amount of unrecognized tax benefits as of December 31, 2014 and 2013 excludes deferred tax assets related to uncertainty in income taxes of $7.2 million and $8.4 million, respectively. As of December 31, 2014 and 2013, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2014, 2013 and 2012, we recognized approximately $0.3 million, $0.2 million and $0.2 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2014, 2013 and 2012, we recognized no penalties in the Consolidated Income Statements. We had approximately $0.7 million and $0.4 million of interest accrued and no penalties accrued on the Consolidated Balance Sheets as of December 31, 2014 and 2013, respectively.

We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months.



	77	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

Our primary tax jurisdictions include the United States and the state of Wisconsin. Currently, the tax years of 2011 through 2014 are subject to Federal examination, and the tax years 2010 through 2014 are subject to examination by the state of Wisconsin.

H -- COMMON EQUITY

Share-Based Compensation Plans: Our employees participate in a plan approved by Wisconsin Energy stockholders that provides a long-term incentive through equity interests in Wisconsin Energy to outside directors, selected officers and key employees of Wisconsin Energy and its subsidiaries. The plan provides for the granting of Wisconsin Energy stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in Wisconsin Energy common stock, cash or a combination thereof. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding Wisconsin Energy stock options held by our employees during the period.

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for Wisconsin Energy share-based awards made to our employees during the years ended December 31:



	2014		2013		2012
	(Millions of Dollars)

Performance units	$	12.7	$	11.9	$	14.2
Stock options	3.6		3.8		2.6
Restricted stock	2.1		1.6		2.0
Share-based compensation expense	$	18.4	$	17.3	$	18.8

Related Tax Benefit	$	7.4	$	6.9	$	7.5

Stock Options: The exercise price of a Wisconsin Energy stock option under the plan is to be no less than 100% of the common stock's fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. Option grants consist of non-qualified stock options that vest on a cliff-basis after a three year period. Options expire no later than 10 years from the date of grant. For further information regarding stock-based compensation and the valuation of Wisconsin Energy stock options, see Note A.

The following is a summary of Wisconsin Energy stock option activity by our employees during 2014:



					Weighted-Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of January 1, 2014	7,688,843		$	26.92
Granted	864,860		$	41.03
Exercised	(2,086,231	)	$	22.95
Forfeited	(17,195	)	$	37.42
Outstanding as of December 31, 2014	6,450,277		$	30.07	5.7	$	146.2

Exercisable as of December 31, 2014	3,682,442		$	24.14	3.9	$	105.3

We expect that substantially all of the outstanding options as of December 31, 2014 will be exercised.



	78	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

In January 2015, the Compensation Committee of the Board of Directors of Wisconsin Energy (Compensation Committee) awarded 495,550 Wisconsin Energy non-qualified stock options with an exercise price of $52.895 to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

The intrinsic value of Wisconsin Energy options exercised during the years ended December 31, 2014, 2013 and 2012 was $47.5 million, $41.2 million and $42.9 million, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $47.9 million, $45.5 million and $45.4 million during the years ended December 31, 2014, 2013 and 2012, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $18.8 million, $16.6 million and zero, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of December 31, 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	1,411,769	$20.88	3.6	1,411,769	$20.88	3.6
$23.88 to $29.35	2,038,633	$25.07	3.7	2,038,633	$25.07	3.7
$34.88 to $41.03	2,999,875	$37.79	8.0	232,040	$35.86	7.4

	6,450,277	$30.07	5.7	3,682,442	$24.14	3.9

The following table summarizes information about non-vested Wisconsin Energy options held by our employees during 2014:



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

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 December 31, 2014	2,767,835		$3.65

As of December 31, 2014, total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $2.0 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

Restricted Shares: The Compensation Committee has also approved grants of Wisconsin Energy restricted stock to certain of our key employees. The following restricted stock activity related to our employees occurred during 2014:



	Number of		Weighted- Average Market
Restricted Shares	Shares		Price
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 December 31, 2014	100,657



	79	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

In January 2015, the Compensation Committee awarded 43,212 restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and one-third of the award vests on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders.

Wisconsin Energy records the market value of the restricted stock awards on the date of grant. We then amortize our share of allocated expense over the vesting period of the awards. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was $2.3 million, $2.8 million and $2.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.9 million, $1.1 million and zero, respectively.

As of December 31, 2014, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $2.1 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Performance Units: In January 2014, 2013 and 2012, the Compensation Committee awarded 224,735, 230,245 and 333,685 Wisconsin Energy performance units, respectively, to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units that will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's common stock over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash. We are accruing our share of compensation costs over the three-year performance period based on our estimate of the final expected value of the awards. Performance units earned as of December 31, 2014, 2013 and 2012 vested and were settled during the first quarter of 2015, 2014 and 2013, and had a total intrinsic value of $11.6 million, $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 $4.2 million, $4.7 million and $6.2 million, respectively. As of December 31, 2014, total compensation cost related to performance units not yet recognized was approximately $10.9 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

In January 2015, the Compensation Committee awarded 187,450 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

We are required to maintain a capital structure that differs from GAAP as it reflects regulatory adjustments. Both the 2013 PSCW rate case order and the 2015 PSCW rate case order require us to maintain a common equity ratio range of between 48.5% and 53.5%. We are in compliance with the common equity ratio range. We must obtain PSCW approval to pay dividends above the test year levels that would cause us to fall below the authorized level of common equity.

We may not pay common dividends to Wisconsin Energy under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.

See Note K for discussion of certain financial covenants related to our bank back-up credit facility.

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



	80	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

I -- PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2014 and 2013:



	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
					(In Millions)
$100 par value, Six Per Cent. Preferred Stock	45,000	44,498	—		$	4.4
$100 par value, Serial Preferred Stock	2,286,500
3.60% Series		260,000	$	101	26.0
$25 par value, Serial Preferred Stock	5,000,000	—	—		—
Total Preferred Stock					$	30.4

J -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

Debentures and Notes: As of December 31, 2014, the maturities of our long-term debt outstanding (excluding obligations under capital leases) were as follows:



	(Millions of Dollars)

2015	$	250.0
2016	—
2017	—
2018	250.0
2019	250.0
Thereafter	1,687.0
Total	$	2,437.0

We amortize debt premiums, discounts and debt issuance costs over the lives of the debt and we include the costs in interest expense.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147.0 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 purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2014 and 2013, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt or included on our Consolidated Statements of Capitalization 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.

Obligations Under Capital Leases

We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power under Wisconsin Energy's PTF strategy. Under capital lease accounting, we have recorded the leased plants and corresponding obligations under the capital leases on our Consolidated Balance Sheets. We treat these agreements as operating leases for rate-making purposes. We record our minimum lease payments under the power purchase contract as purchased power expense on the Consolidated Income Statements. We record the lease payments under our PTF leases as rent expense in other operation and maintenance in the Consolidated Income Statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see Regulatory Assets - Deferred plant related -- capital leases in Note C).

Power Purchase Commitment: In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to



	81	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

expire. We recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.

PWGS: We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. The leased plants and corresponding obligations for the plants have been recorded at the estimated fair value of $682.7 million. We are amortizing the leased plants on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.1 million in the year 2021 for PWGS 1 and to approximately $127.9 million in the year 2024 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for the plants was $637.1 million as of December 31, 2014, and will decrease to zero over the remaining lives of the contracts.

Oak Creek Expansion: We are leasing OC 1, OC 2 and the common facilities, which are also utilized by our Oak Creek Units 5-8, from We Power under PSCW approved leases. We are amortizing the leased plants on a straight-line basis over the 30-year term of the leases. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively. The leased plants and corresponding capital lease obligations have been recorded at the estimated fair value of $2,025.6 million. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $537.6 million in the year 2029 for OC 1 and to approximately $442.0 million in the year 2030 for OC2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases was $2,096.5 million as of December 31, 2014, and will decrease to zero over the remaining life of the contracts.

We paid the following lease payments during 2014, 2013 and 2012:



	2014		2013		2012
	(Millions of Dollars)

Long-term power purchase commitment	$	34.9	$	33.7	$	32.5
PWGS	99.2		99.1		99.0
Oak Creek Expansion	277.8		274.9		269.3
Total	$	411.9	$	407.7	$	400.8

The following table summarizes our capitalized leased facilities as of December 31:



Capital Lease Assets	2014			2013
	(Millions of Dollars)

Long-term Power Purchase Commitment
Under capital lease	$	140.3		$	140.3
Accumulated amortization	(98.3		)	(92.5		)
Total Long-term Power Purchase Commitment	$	42.0		$	47.8

PWGS
Under capital lease	$	682.7		$	681.5
Accumulated amortization	(217.6		)	(190.1		)
Total PWGS	$	465.1		$	491.4

Oak Creek Expansion
Under capital lease	$	2,025.6		$	1,991.1
Accumulated amortization	(317.7		)	(251.3		)
Total Oak Creek	$	1,707.9		$	1,739.8

Total Leased Facilities	$	2,215.0		$	2,279.0



	82	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2014 are as follows:



	Power
	Purchase						Oak Creek
Capital Lease Obligations	Commitment			PWGS			Expansion			Total
	(Millions of Dollars)

2015	$	43.5		$	99.3		$	296.4		$	439.2
2016	45.1			99.3			311.0			455.4
2017	13.9			99.3			311.4			424.6
2018	14.7			99.3			311.4			425.4
2019	15.5			99.3			311.4			426.2
Thereafter	41.3			1,184.7			6,378.5			7,604.5
Total Minimum Lease Payments	174.0			1,681.2			7,920.1			9,775.3
Less: Estimated Executory Costs	(54.7		)	—			—			(54.7		)
Net Minimum Lease Payments	119.3			1,681.2			7,920.1			9,720.6
Less: Interest	(34.8		)	(1,044.1		)	(5,823.6		)	(6,902.5		)
Present Value of Net
Minimum Lease Payments	84.5			637.1			2,096.5			2,818.1
Less: Due Currently	(24.6		)	(10.2		)	(70.8		)	(105.6		)
Total Capital Lease Obligations	$	59.9		$	626.9		$	2,025.7		$	2,712.5

K -- SHORT-TERM DEBT

Our commercial paper balance and the corresponding weighted-average interest rate as of December 31 are shown in the following table:



	2014		2013
		Interest		Interest
	Balance	Rate	Balance	Rate
	(Millions of Dollars, except for percentages)

Commercial paper	$306.8	0.25%	$174.5	0.22%

The following information relates to commercial paper outstanding for the years ended December 31:



	2014			2013
	(Millions of Dollars, except for percentages)

Maximum Commercial Paper Outstanding	$	401.0		$	354.5
Average Commercial Paper Outstanding	$	179.5		$	98.0
Weighted-Average Interest Rate	0.22		%	0.22		%

We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 65%.

As of December 31, 2014, we had approximately $494.9 million of available, undrawn lines under our bank back-up credit facility and $306.8 million of commercial paper outstanding that was supported by the available lines of credit. In December 2014, we amended our credit facility to extend its expiration from December 2017 to December 2019. As of December 31, 2014, our subsidiary had a $22.4 million note payable to Wisconsin Energy with a weighted-average interest rate of 6.75%.



	83	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 (ERISA) defaults and change of control.

As of December 31, 2014, we were in compliance with all financial covenants.

L -- 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 December 31, 2014, we recognized $8.4 million in regulatory assets and $12.2 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 other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $0.6 million is recorded in other deferred charges and other assets as of December 31, 2014, and the long-term portion of derivative liabilities of $0.7 million is recorded in other deferred credit and other liabilities as of December 31, 2014. Our Consolidated Balance Sheets as of December 31, 2014 and 2013 include:



	December 31, 2014				December 31, 2013
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	2.3	$	7.1	$	2.8	$	0.1
Fuel Oil	—		—		0.6		—
FTRs	7.0		—		3.5		—
Coal	3.3		0.2		2.1		0.2
Total	$	12.6	$	7.3	$	9.0	$	0.3

Our Consolidated Income Statements include gains (losses) on derivative instruments used in our risk management strategies under fuel and purchased power for those commodities supporting our electric operations and under cost of gas sold for the natural gas sold to our customers. Our estimated notional volumes and gains (losses) for the years ended December 31, 2014 and 2013 were as follows:



	2014			2013
	Volume	Gains		Volume	Gains (Losses)
		(Millions of Dollars)			(Millions of Dollars)
Natural Gas	21.4 million Dth	$	4.0	24.0 million Dth	$	(4.0	)
Fuel Oil	9.2 million gallons	0.5		8.6 million gallons	0.5
FTRs	26.1 million MWh	12.7		25.3 million MWh	14.9
Total		$	17.2		$	11.4

As of December 31, 2014 and 2013, we posted collateral of $6.9 million and zero, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.



	84	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

The fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. The table below shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet as of December 31, 2014 and 2013.



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

Gross Amount Recognized on the Balance Sheet	$	12.6		$	7.3		$	9.0	$	0.3
Gross Amount Not Offset on Balance Sheet (a)	(0.4		)	(6.8		)	—		—
Net Amount	$	12.2		$	0.5		$	9.0	$	0.3


(a)	Gross Amount Not Offset on Balance Sheet includes cash collateral posted of $6.4 million and zero as of December 31, 2014 and 2013, respectively.

M -- FAIR VALUE MEASUREMENTS

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

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

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

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

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



	85	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

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 December 31, 2014
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	0.4	$	5.2	$	7.0	$	12.6
Total	$	0.4	$	5.2	$	7.0	$	12.6
Liabilities:
Derivatives	$	6.8	$	0.5	$	—	$	7.3
Total	$	6.8	$	0.5	$	—	$	7.3



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.



	86	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

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



	2014			2013
	(Millions of Dollars)

Balance as of January 1	$	3.5		$	4.7
Realized and unrealized gains (losses)	—			—
Purchases	15.6			10.6
Issuances	—			—
Settlements	(12.1		)	(11.8		)
Transfers in and/or out of Level 3	—			—
Balance as of December 31	$	7.0		$	3.5

Derivative instruments reflected in Level 3 of the hierarchy include MISO 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 L -- 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 as of December 31 are as follows:



	2014				2013
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)

Preferred stock, no redemption required	$	30.4	$	27.1	$	30.4	$	26.0
Long-term debt including current portion	$	2,437.0	$	2,759.6	$	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.

N -- BENEFITS

Pensions and Other Post-retirement Benefits: We participate in Wisconsin Energy's defined benefit pension plans that cover substantially all of our employees. Generally, employees who started with the Company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Approximately half of our projected benefit obligation relates to benefits based upon years of service and final average salary. New management employees hired after December 31, 2014 will receive a 6% annual Company contribution to their 401(k) plan instead of being enrolled in the defined benefit plans.

We also participate in Wisconsin Energy's OPEB plans that cover substantially all of our employees. The health care plans are contributory with participants' contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees.



	87	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

The assets, obligations and the components of our pension costs are allocated by Wisconsin Energy's actuary to each of the participating companies as if each participating company had its own plan. The disclosures below are based on an allocation to us of the amounts for Wisconsin Energy's pension plans.

We use a year-end measurement date to measure the funded status of all of the pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset.

The following table presents details about the pension and OPEB plans:



	Pension						OPEB
	2014			2013			2014			2013
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,223.1		$	1,310.3		$	292.4		$	305.4
Service cost	9.4			13.9			8.1			9.5
Interest cost	59.3			52.4			14.4			12.7
Participants' contributions	—			—			8.4			8.1
Plan amendments	—			(0.9		)	(5.2		)	—
Actuarial loss (gain)	110.8			(73.9		)	24.3			(22.7		)
Other accrued benefits	(0.1		)	—			—			—
Gross benefits paid	(87.3		)	(78.7		)	(21.1		)	(21.3		)
Federal subsidy on benefits paid	N/A			N/A			1.0			0.7
Benefit Obligation at December 31	$	1,315.2		$	1,223.1		$	322.3		$	292.4

Change in Plan Assets
Fair Value at January 1	$	1,168.9		$	1,121.1		$	222.4		$	194.8
Actual earnings on plan assets	71.2			119.0			12.0			30.7
Employer contributions	7.2			7.5			3.2			10.1
Participants' contributions	—			—			8.4			8.1
Gross benefits paid	(87.3		)	(78.7		)	(21.1		)	(21.3		)
Fair Value at December 31	$	1,160.0		$	1,168.9		$	224.9		$	222.4

Net liability	$	155.2		$	54.2		$	97.4		$	70.0

Amounts recognized in our Consolidated Balance Sheets as of December 31 related to the funded status of the benefit plans consisted of:



	Pension				OPEB
	2014		2013		2014		2013
	(Millions of Dollars)

Other long-term assets	$	—	$	34.3	$	1.9	$	1.6
Other long-term liabilities	$	155.2	$	88.5	$	99.3	$	71.6
Net liability	$	155.2	$	54.2	$	97.4	$	70.0

The accumulated benefit obligation for all defined benefit plans was $1,314.3 million and $1,222.3 million as of December 31, 2014 and 2013, respectively.



	88	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31 and are recorded as a regulatory asset on our balance sheet:



	Pension				OPEB
	2014		2013		2014			2013
	(Millions of Dollars)

Net actuarial loss (gain)	$	476.4	$	384.7	$	20.7		$	(7.6	)
Prior service costs (credits)	6.3		8.3		(5.2		)	(1.7		)
Total - Regulatory Assets (Liabilities)	$	482.7	$	393.0	$	15.5		$	(9.3	)

We estimate that 2015 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs (credits) referred to above of $38.0 million and $(0.2) million, respectively.

The components of net periodic pension and OPEB costs for the years ended December 31 are as follows:



	Pension									OPEB
	2014			2013			2012			2014			2013			2012
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	9.4		$	13.9		$	19.8		$	8.1		$	9.5		$	9.8
Interest cost	59.3			52.4			56.8			14.4			12.7			16.7
Expected return on plan assets	(79.1		)	(77.2		)	(71.8		)	(16.2		)	(14.5		)	(13.0		)
Amortization of:
Transition obligation	—			—			—			—			—			0.3
Prior service cost (credit)	2.0			2.2			2.1			(1.7		)	(1.9		)	(1.9		)
Actuarial loss	26.9			41.7			30.6			0.2			1.5			5.0
Settlement charge	—			1.5			—			—			—			—
Other	—			—			0.4			—			—			—
Net Periodic Benefit Cost	$	18.5		$	34.5		$	37.9		$	4.8		$	7.3		$	16.9



	Pension			OPEB
	2014	2013	2012	2014	2013	2012
Weighted-Average assumptions used to
determine benefit obligations as of Dec. 31
Discount rate	4.15%	5.00%	4.10%	4.20%	4.95%	4.15%
Rate of compensation increase	4.00%	4.00%	4.00%	N/A	N/A	N/A

Weighted-Average assumptions used to
determine net cost for year ended Dec. 31
Discount rate	5.00%	4.10%	5.05%	4.95%	4.15%	5.20%
Expected return on plan assets	7.25%	7.25%	7.25%	7.50%	7.50%	7.50%
Rate of compensation increase	4.00%	4.00%	4.00%	N/A	N/A	N/A

Assumed health care cost trend rates as of Dec. 31
Health care cost trend rate assumed for next year (Pre 65 / Post 65)				7.5%/7.5%	7.5%/7.5%	7.5%/7.5%
Rate that the cost trend rate gradually adjusts to				5.00%	5.00%	5.00%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)				2021/2021	2021/2021	2017/2017

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2014, 2013 and 2012. Wisconsin Energy consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.



	89	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

A one-percentage-point change in assumed health care cost trend rates would have the following effects:



	1% Increase		1% Decrease
	(Millions of Dollars)
Effect on
Post-retirement benefit obligation	$	29.3	$	(24.4	)
Total of service and interest cost components	$	3.1	$	(2.5	)

We use various Employees' Benefit Trusts to fund a major portion of OPEB. The majority of the trusts' assets are mutual funds.

Plan Assets: Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.

The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

Previously, our pension plan target allocation was 45% equity investments and 55% fixed income investments. In late 2014, we began transitioning to a target asset allocation of 35% equity investments, 55% fixed income investments and 10% private equity and real estate investments. The current OPEB target asset allocation is 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and U.S. Treasuries.

The following table summarizes the fair value of our share of plan assets by asset category within the fair value hierarchy (for further level information, see Note M):



	As of December 31, 2014
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)

Cash and Cash Equivalents	$	5.1	$	—	$	—	$	5.1
Equities:
U.S. Equity	404.5		—		—		404.5
International Equity	103.3		23.9		—		127.2
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	34.2		481.2		—		515.4
International Bonds	63.7		34.8		—		98.5
Private equity and real estate	—		—		9.3		9.3
Total	$	610.8	$	539.9	$	9.3	$	1,160.0



	90	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K



	As of December 31, 2013
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)

Cash and Cash Equivalents	$	16.9	$	—	$	—	$	16.9
Equities:
U.S. Equity	418.5		—		—		418.5
International Equity	117.8		28.8		—		146.6
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	87.3		407.0		—		494.3
International Bonds	62.9		29.7		—		92.6
Total	$	703.4	$	465.5	$	—	$	1,168.9


(a)	This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

The following table summarizes the fair value of our share of OPEB plan assets by asset category within the fair value hierarchy:



	As of December 31, 2014
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)

Cash and Cash Equivalents	$	0.9	$	—	$	—	$	0.9
Equities:
U.S. Equity	98.4		—		—		98.4
International Equity	28.5		1.7		—		30.2
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	2.4		75.8		—		78.2
International Bonds	11.8		4.7		—		16.5
Private equity and real estate	—		—		0.7		0.7
Total	$	142.0	$	82.2	$	0.7	$	224.9



	As of December 31, 2013
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)

Cash and Cash Equivalents	$	1.8	$	—	$	—	$	1.8
Equities:
U.S. Equity	100.5		—		—		100.5
International Equity	31.8		1.9		—		33.7
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	5.7		65.4		—		71.1
International Bonds	11.4		3.9		—		15.3
Total	$	151.2	$	71.2	$	—	$	222.4


(a)	This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

In December 2014, our pension and OPEB plans began investing in private equity funds which are a Level 3 investment.



	91	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

Cash Flows:

Historical employer contributions:



	Pension
Year	Qualified		Non-Qualified		OPEB
	(Millions of Dollars)

2012	$	88.5	$	6.0	$	13.6
2013	$	—	$	7.5	$	10.1
2014	$	—	$	7.2	$	3.2

In January 2015, we contributed $100.0 million to the qualified pension plan. Future contributions to the plans will be dependent upon many factors, including the performance of plan assets, long-term discount rates and mortality rates.

Estimated benefit payments:





Year	Pension		Gross OPEB
	(Millions of Dollars)

2015	$	91.8	$	13.9
2016	$	91.5	$	14.8
2017	$	92.1	$	16.0
2018	$	89.5	$	17.1
2019	$	89.4	$	18.2
2020-2024	$	429.5	$	99.3

Savings Plans: We sponsor savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $13.0 million, $13.0 million and $12.5 million during 2014, 2013 and 2012, respectively.

Postemployment Benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $1.8 million and $2.8 million as of December 31, 2014 and 2013, respectively.

O -- SEGMENT REPORTING

We are a subsidiary of Wisconsin Energy and have organized our reportable segments according to how we are currently regulated. Our reportable operating segments include electric, natural gas and steam utility segments. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our electric utility engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas in three service areas in southeastern, east central and northern Wisconsin. Our steam utility produces, distributes and sells steam to space heating and processing customers in the Milwaukee, Wisconsin area.

Total asset information is not provided for reportable segments because as an integrated electric, natural gas and steam utility, significant assets are not dedicated to a specific reportable segment. Reporting assets by segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the reportable segments on a stand-alone basis.



	92	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

Summarized financial information concerning our reportable segments for each of the three years ended December 31, 2014 is shown in the following table:



	Reportable Segments
Year Ended	Electric		Gas		Steam			Other (a)		Total
	(Millions of Dollars)
December 31, 2014
Operating Revenues (b)	$	3,401.1	$	614.2	$	44.1		$	—	$	4,059.4
Depreciation and Amortization	$	261.5	$	30.5	$	3.7		$	—	$	295.7
Operating Income (c)	$	565.6	$	77.2	$	7.6		$	—	$	650.4
Equity in Earnings
of Transmission Affiliate	$	57.9	$	—	$	—		$	—	$	57.9
Capital Expenditures	$	470.2	$	67.9	$	2.8		$	—	$	540.9

December 31, 2013
Operating Revenues (b)	$	3,308.7	$	451.9	$	39.6		$	—	$	3,800.2
Depreciation and Amortization	$	249.5	$	25.5	$	3.6		$	—	$	278.6
Operating Income (Loss) (c)	$	533.2	$	69.8	$	2.9		$	—	$	605.9
Equity in Earnings
of Transmission Affiliate	$	60.2	$	—	$	—		$	—	$	60.2
Capital Expenditures	$	438.5	$	57.8	$	10.6		$	—	$	506.9

December 31, 2012
Operating Revenues (b)	$	3,193.9	$	385.1	$	34.3		$	—	$	3,613.3
Depreciation and Amortization	$	230.3	$	23.9	$	3.4		$	—	$	257.6
Operating Income (c)	$	536.5	$	50.0	$	(3.2	)	$	—	$	583.3
Equity in Earnings
of Transmission Affiliate	$	57.6	$	—	$	—		$	—	$	57.6
Capital Expenditures	$	524.9	$	50.8	$	—		$	0.1	$	575.8


(a)	Other includes primarily non-utility property and investments, materials and supplies, deferred charges and other corporate items.


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


(c)	We evaluate operating income to manage our utility business. Equity in Earnings of Transmission Affiliate, Interest Expense and Income Taxes are not included in segment operating income.

P -- RELATED PARTIES

We provide to and receive from certain of our Wisconsin Energy affiliates managerial, financial, accounting, legal, data processing and other services in accordance with service agreements approved by the PSCW. In addition, we make lease payments to We Power for PWGS 1, PWGS 2, OC 1 and OC 2. We also receive and/or provide certain services to other associated companies in which we have, or Wisconsin Energy has, an equity investment.

American Transmission Company LLC: As of December 31, 2014, we have a 23.0% interest in ATC. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which is reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while projects are under construction. ATC reimburses us for these costs when new generation is placed in service.



	93	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

During the years ended December 31, 2014, 2013 and 2012, our equity in earnings and distributions received from ATC were as follows:



Equity Investee	2014		2013		2012
	(Millions of Dollars)
Equity in Earnings	$	57.9	$	60.2	$	57.6

Distributions Received	$	50.5	$	47.8	$	46.1

Summary financial information as of December 31 from the financial statements of ATC is as follows:



	2014		2013		2012
	(Millions of Dollars)

Operating Revenues	$	635.0	$	626.3	$	603.3
Operating Income	$	327.6	$	331.3	$	322.2
Net Income	$	238.7	$	247.6	$	237.4

Current Assets	$	66.4	$	80.7	$	63.1
Non-Current Assets	$	3,728.7	$	3,509.5	$	3,274.7
Current Liabilities	$	313.1	$	381.5	$	251.5
Non-Current Liabilities	$	1,864.8	$	1,676.2	$	1,645.8

We provided and received services from the following associated companies during 2014, 2013 and 2012:



Company	2014		2013		2012
	(Millions of Dollars)
Affiliate

Services Provided
We Power (excluding lease payments)	$	41.5	$	2.8	$	2.3
Wisconsin Gas	$	81.7	$	83.4	$	78.7
Wisconsin Energy	$	11.3	$	5.6	$	5.6
Other	$	1.5	$	1.6	$	1.2

Services Received
We Power (including lease payments)	$	389.0	$	381.7	$	375.3
Wisconsin Gas	$	20.6	$	23.6	$	16.6
Wisconsin Energy	$	15.2	$	10.2	$	23.9

Equity Investee - ATC

Services Provided	$	8.1	$	9.0	$	8.2

Services Received	$	231.4	$	234.2	$	222.7



	94	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

As of December 31, 2014 and 2013, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:



Equity Investee	2014		2013
	(Millions of Dollars)
Accounts Receivable
Services provided	$	0.6	$	0.6

Accounts Payable
Services received	$	19.3	$	19.5

Q -- COMMITMENTS AND CONTINGENCIES

Operating Leases: We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2018. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases, including leases for coal cars.

Future minimum payments for the next five years and thereafter for our operating lease contracts are as follows:



	(Millions of Dollars)

2015	$	5.2
2016	3.9
2017	3.2
2018	3.1
2019	1.2
Thereafter	21.5
Total	$	38.1

Divested Assets: We provided customary indemnifications to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corporation, in connection with the sale of our interest in Edgewater Generating Unit 5.

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 WDNR in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Manufactured Gas Plant Sites: We have identified several sites at which we or a predecessor company historically owned or operated a manufactured gas plant. These sites have been substantially remediated or are at various stages of investigation, monitoring and remediation. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon on-going analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $6 million to $12 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 December 31, 2014 and 2013, we established reserves of $6.5 million and $10.8 million, respectively, related to future remediation costs.



	95	Wisconsin Electric Power Company



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)	2014 Form 10-K

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.

Coal Combustion Product Landfill Sites: We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required various levels of monitoring or remediation. Where we have become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. During 2014, 2013 and 2012, we incurred $0.1 million, $0.1 million and $0.3 million, respectively, in landfill remediation expenses. As of December 31, 2014, we have no reserves established related to coal combustion product landfill sites.

Valley Power Plant Title V Air Permit: The WDNR renewed VAPP's Title V operating permit in February 2011. The term of the permit is five years. In March 2011, the Sierra Club petitioned the EPA for additional reductions and monitoring for particulate matter and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of this proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

R -- SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2014, we paid $117.9 million in interest, net of amounts capitalized, and paid $20.8 million in income taxes, net of refunds. During the year ended December 31, 2013, we paid $120.5 million in interest, net of amounts capitalized, and received $39.2 million in net refunds from income taxes. During the year ended December 31, 2012, we paid $109.0 million in interest, net of amounts capitalized, and received $91.2 million in net refunds from income taxes.

As of December 31, 2014, 2013 and 2012, the amount of accounts payable related to capital expenditures was $1.7 million, $4.6 million and $15.7 million, respectively.

S -- SUBSEQUENT EVENT

On January 12, 2015, we, along with Wisconsin Energy, entered into an agreement with the Governor of the State of Michigan, the Attorney General of the State of Michigan, the Staff of the MPSC and the owners of two large mines in the Upper Peninsula of Michigan, to resolve all objections these parties raised at the FERC and MPSC related to Wisconsin Energy’s proposed acquisition of Integrys. We believe that this agreement is in the best interest of our customers. In connection with the agreement, we entered into a non-binding term sheet to sell our Michigan electric distribution assets and the Presque Isle Power Plant to a third party. The carrying value of these assets is approximately $292 million as of December 31, 2014.

We are working to achieve a definitive agreement for the sale of these assets by the end of March 2015. This agreement would be subject to approval by several regulatory agencies including FERC, the PSCW and the MPSC. If we are able to reach a definitive agreement consistent with the financial terms of the non-binding term sheet, we would seek the recovery of approximately $190 million of net unrecovered plant costs from our remaining customers.



	96	Wisconsin Electric Power Company



	2014 Form 10-K

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Electric Power Company:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary (the "Company") as of December 31, 2014 and 2013, and the related consolidated income statements, statements of common equity, and statements of cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 27, 2015



	97	Wisconsin Electric Power Company



	2014 Form 10-K


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


ITEM 9A.	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.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of Wisconsin Electric Power Company's internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that Wisconsin Electric Power Company's internal control over financial reporting was effective as of December 31, 2014.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

This annual report does not include an attestation report of the Company's independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the Company's independent registered public accounting firm pursuant to rules of the SEC that permit the Company to provide only management's report in this annual report.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


ITEM 9B.	OTHER INFORMATION

None



	98	Wisconsin Electric Power Company



	2014 Form 10-K

PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT

The information under "Election of Directors", "Section 16(a) Beneficial Ownership Reporting Compliance", "Corporate Governance - Frequently Asked Questions: What is the process used to identify director nominees and how do I recommend a nominee to WEC's Corporate Governance Committee?", "Corporate Governance - Frequently Asked Questions: Are the Audit and Oversight and Compensation Committees comprised solely of independent directors?", "Corporate Governance - Frequently Asked Questions: Are all the members of the Audit Committee financially literate and does the committee have an 'audit committee financial expert'?", "Corporate Governance - Frequently Asked Questions: Does the Board have a nominating committee?" and "Committees of the Board of Directors -- Audit and Oversight" in our Definitive Information Statement on Schedule 14C to be filed with the SEC for our Annual Meeting of Stockholders to be held April 30, 2015 (the "2015 Annual Meeting Information Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.

Wisconsin Energy has adopted a written code of ethics, referred to as its Code of Business Conduct. We are a subsidiary of Wisconsin Energy, and as such, all of our directors, executive officers and employees, including our principal executive officer, principal financial officer and principal accounting officer, have a responsibility to comply with Wisconsin Energy's Code of Business Conduct. Wisconsin Energy has posted its Code of Business Conduct in the "Governance" section on its website, www.wisconsinenergy.com. Wisconsin Energy has not provided any waiver to the Code for any director, executive officer or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on Wisconsin Energy's website or in a current report on Form 8-K.


ITEM 11.	EXECUTIVE COMPENSATION

The information under "Compensation Discussion and Analysis", "Executive Compensation", "Director Compensation", "Committees of the Board of Directors -- Compensation", "Compensation Committee Report", "Risk Analysis of Compensation Policies and Practices" and "Certain Relationships and Related Transactions -- Compensation Committee Interlocks and Insider Participation" in the 2015 Annual Meeting Information Statement is incorporated herein by reference.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

All of our Common Stock is owned by our parent company, Wisconsin Energy Corporation, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201. Our directors, director nominees and executive officers do not own any of our voting securities. The information concerning their beneficial ownership in Wisconsin Energy common stock set forth under "Stock Ownership of Directors, Nominees and Executive Officers" in the 2015 Annual Meeting Information Statement is incorporated herein by reference.

We do not have any equity compensation plans under which our equity securities may be issued. Our directors, officers and certain employees participate in the compensation plans of Wisconsin Energy Corporation.



	99	Wisconsin Electric Power Company



	2014 Form 10-K


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information under "Corporate Governance - Frequently Asked Questions: Who are the independent directors?", "Corporate Governance - Frequently Asked Questions: What are the Board's standards of independence?", "Corporate Governance - Frequently Asked Questions: Are the Audit and Oversight and Compensation Committees comprised solely of independent directors?", "Corporate Governance - Frequently Asked Questions: Does the Company have policies and procedures in place to review and approve related party transactions?" and "Certain Relationships and Related Transactions" in the 2015 Annual Meeting Information Statement is incorporated herein by reference. A full description of the guidelines our Board uses to determine director independence is located in Appendix A of Wisconsin Energy's Corporate Governance Guidelines, which can be found on its website, www.wisconsinenergy.com.


ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding the fees paid to, and services performed by, our independent auditors and the pre-approval policy of our audit and oversight committee under "Independent Auditors' Fees and Services" in the 2015 Annual Meeting Information Statement is incorporated herein by reference.

PART IV


ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



(a) 1.	FINANCIAL STATEMENTS AND REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM INCLUDED IN PART II OF THIS REPORT



	Description		Page in 10-K

	Consolidated Income Statements for the three years ended December 31, 2014.		64

	Consolidated Balance Sheets at December 31, 2014 and 2013.		65

	Consolidated Statements of Cash Flows for the three years ended December 31, 2014.		67

	Consolidated Statements of Capitalization at December 31, 2014 and 2013.		68

	Consolidated Statements of Common Equity for the three years ended December 31, 2014.		69

	Notes to Consolidated Financial Statements.		70

	Report of Independent Registered Public Accounting Firm.		97



2		FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT

		Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2014.

		Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.



	100	Wisconsin Electric Power Company



	2014 Form 10-K



3		EXHIBITS AND EXHIBIT INDEX

		See the Exhibit Index included as the last part of this report, which is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the Exhibit Index by two asterisks (**) following the description of the exhibit.



	101	Wisconsin Electric Power Company



	2014 Form 10-K



SCHEDULE II	VALUATION AND QUALIFYING ACCOUNTS



Allowance for Doubtful Accounts	Balance at Beginning of the Period		Expense		Deferral		Net Write-offs			Balance at End of the Period
	(Millions of Dollars)
December 31, 2014	$	39.7	$	31.3	$	10.0	$	(34.2	)	$	46.8
December 31, 2013	$	36.7	$	31.4	$	2.7	$	(31.1	)	$	39.7
December 31, 2012	$	36.9	$	8.7	$	20.7	$	(29.6	)	$	36.7



	102	Wisconsin Electric Power Company



	2014 Form 10-K

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

	By	/s/GALE E. KLAPPA
Date:	February 27, 2015	Gale E. Klappa, Chairman of the Board, President
		and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



/s/GALE E. KLAPPA		February 27, 2015
Gale E. Klappa, Chairman of the Board, President and Chief
Executive Officer and Director -- Principal Executive Officer

/s/J. PATRICK KEYES		February 27, 2015
J. Patrick Keyes, Executive Vice President and Chief
Financial Officer -- Principal Financial Officer

/s/STEPHEN P. DICKSON		February 27, 2015
Stephen P. Dickson, Vice President and
Controller -- Principal Accounting Officer

/s/JOHN F. BERGSTROM		February 27, 2015
John F. Bergstrom, Director

/s/BARBARA L. BOWLES		February 27, 2015
Barbara L. Bowles, Director

/s/PATRICIA W. CHADWICK		February 27, 2015
Patricia W. Chadwick, Director

/s/CURT S. CULVER		February 27, 2015
Curt S. Culver, Director

/s/THOMAS J. FISCHER		February 27, 2015
Thomas J. Fischer, Director

/s/HENRY W. KNUEPPEL		February 27, 2015
Henry W. Knueppel, Director

/s/ULICE PAYNE, JR.		February 27, 2015
Ulice Payne, Jr., Director

/s/MARY ELLEN STANEK		February 27, 2015
Mary Ellen Stanek, Director



	103	Wisconsin Electric Power Company



	2014 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY

(Commission File No. 001-01245)

EXHIBIT INDEX

Annual Report on Form 10-K

For the year ended December 31, 2014

The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)



Number	Exhibit

3	Articles of Incorporation and By-laws

	3.1*	Restated Articles of Incorporation of Wisconsin Electric Power Company, as amended and restated effective January 10, 1995. (Exhibit (3)-1 to Wisconsin Electric Power Company's 12/31/94 Form 10-K.)

	3.2*	Bylaws of Wisconsin Electric Power Company, as amended to May 1, 2000. (Exhibit 3.1 to Wisconsin Electric Power Company's 03/31/00 Form 10-Q.)

4	Instruments defining the rights of security holders, including indentures

	4.1*	Reference is made to Article III of the Restated Articles of Incorporation of Wisconsin Electric Power Company. (Exhibit 3.1 herein.)

	Indentures and Securities Resolutions:

	4.2*	Indenture for Debt Securities of Wisconsin Electric Power Company (the "Wisconsin Electric Indenture"), dated December 1, 1995. (Exhibit (4)-1 to Wisconsin Electric's 12/31/95 Form 10-K.)

	4.3*	Securities Resolution No. 1 of Wisconsin Electric under the Wisconsin Electric Indenture, dated December 5, 1995. (Exhibit (4)-2 to Wisconsin Electric's 12/31/95 Form 10-K.)

	4.4*	Securities Resolution No. 3 of Wisconsin Electric under the Wisconsin Electric Indenture, dated May 27, 1998. (Exhibit (4)-1 to Wisconsin Electric's 06/30/98 Form 10-Q.)

	4.5*	Securities Resolution No. 5 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to Wisconsin Electric's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)

	4.6*	Securities Resolution No. 7 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 2, 2006. (Exhibit 4.1 to Wisconsin Electric's 11/02/06 Form 8-K.)

	4.7*	Securities Resolution No. 9 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2008. (Exhibit 4.1 to Wisconsin Electric's 12/08/08 Form 8-K.)



	E-1	Wisconsin Electric Power Company



	2014 Form 10-K



Number	Exhibit

	4.8*	Securities Resolution No. 10 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2009. (Exhibit 4.1 to Wisconsin Electric's 12/08/09 Form 8-K.)

	4.9*	Securities Resolution No. 11 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of September 7, 2011. (Exhibit 4.1 to Wisconsin Electric's 09/07/11 Form 8-K.)

	4.10*	Securities Resolution No. 12 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 5, 2012. (Exhibit 4.1 to Wisconsin Electric's 12/05/12 Form 8-K.)

	4.11*	Securities Resolution No. 13 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of June 10, 2013. (Exhibit 4.1 to Wisconsin Electric’s 06/10/13 Form 8-K.)

	4.12*	Securities Resolution No. 14 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 12, 2014. (Exhibit 4.1 to Wisconsin Electric's 05/12/14 Form 8-K.)

		Certain agreements and instruments with respect to unregistered long-term debt not exceeding 10 percent of the total assets of the Registrant and its subsidiary on a consolidated basis have been omitted as permitted by related instructions. The Registrant agrees pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreements and instruments.

10	Material Contracts

	10.1*	Wisconsin Energy Corporation Supplemental Pension Plan, Amended and Restated Effective as of January 1, 2015. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/31/2014 Form 10-K (File No. 001-09057).)** See Note.

	10.2*	Service Agreement, dated April 25, 2000, between Wisconsin Electric Power Company and Wisconsin Gas LLC. (Exhibit 10.32 to Wisconsin Energy Corporation's 12/31/00 Form 10-K (File No. 001-09057).)

	10.3*	Service Agreement, dated December 29, 2000, between Wisconsin Electric Power Company and American Transmission Company LLC. (Exhibit 10.33 to Wisconsin Energy Corporation's 12/31/00 Form 10-K (File No. 001-09057).)

	10.4*	Legacy Wisconsin Energy Corporation Executive Deferred Compensation Plan, Amended and Restated as of January 1, 2015. (Exhibit 10.4 to Wisconsin Energy Corporation's 12/31/2014 Form 10-K (File No. 001-09057).)** See Note

	10.5*	Wisconsin Energy Corporation Executive Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2015. (Exhibit 10.5 to Wisconsin Energy Corporation's 12/31/2014 Form 10-K (File No. 001-09057).)** See Note.

	10.6*	Directors' Deferred Compensation Plan of Wisconsin Energy Corporation, as amended and restated as of May 1, 2004 (the "Legacy DDCP"). (Exhibit 10.3 to Wisconsin Energy Corporation's 06/30/04 Form 10-Q (File No. 001-09057).)** See Note.

	10.7*	First Amendment to the Legacy DDCP, effective as of January 1, 2005. (Exhibit 10.15 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.



	E-2	Wisconsin Electric Power Company



	2014 Form 10-K



Number	Exhibit

	10.8*	Wisconsin Energy Corporation Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2015. (Exhibit 10.8 to Wisconsin Energy Corporation's 12/31/2014 Form 10-K (File No. 001-09057).)** See Note.

	10.9*	Wisconsin Energy Corporation Non-Qualified Retirement Savings Plan, Effective January 1, 2015. (Exhibit 10.9 to Wisconsin Energy Corporation's 12/31/2014 Form 10-K (File No. 001-09057).)** See Note.

	10.10*	Wisconsin Energy Corporation Death Benefit Only Plan, as amended and restated as of July 22, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/10 Form 10-Q (File No. 001-09057).)** See Note.

	10.11*	Wisconsin Energy Corporation Short-Term Performance Plan, as amended and restated effective as of January 1, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/03/09 Form 8-K (File No. 001-09057).)** See Note.

	10.12*	Wisconsin Energy Corporation Amended and Restated Executive Severance Policy, effective as of January 1, 2008. (Exhibit 10.18 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.13*	Wisconsin Energy Corporation 2014 Rabbi Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 23, 2015, regarding the trust established to provide a source of funds to assist in meeting the liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.13 to Wisconsin Energy Corporation's 12/31/14 Form 10-K (File No. 001-09057).)** See Note.

	10.14*	Affiliated Interest Agreement (Service Agreement), dated December 12, 2002, by and among Wisconsin Energy Corporation and its affiliates. (Exhibit 10.14 to Wisconsin Energy Corporation's 12/31/02 Form 10-K (File No. 001-09057).)

	10.15*	Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Gale E. Klappa, dated as of December 29, 2008. (Exhibit 10.25 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.16*	Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Allen L. Leverett, dated as of December 30, 2008. (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.17*	Terms of Employment for J. Patrick Keyes. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/12 Form 10-Q (File No. 001-09057).)** See Note.

	10.18*	Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of December 20, 2010. (Exhibit 10.20 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.

	10.19*	Amendment to the Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of August 15, 2011. (Exhibit 10.21 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.



	E-3	Wisconsin Electric Power Company



	2014 Form 10-K



Number	Exhibit

	10.20*	Terms of Employment for Susan H. Martin. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/12 Form 10-Q (File No. 001-09057).)**See Note.

	10.21*	Supplemental Pension Benefit agreement between Wisconsin Energy Corporation and Stephen Dickson, effective May 23, 2001. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/01 Form 10-Q (File No. 001-09057).)** See Note.

	10.22*	Amendment to the Supplemental Pension Benefit Agreement between Wisconsin Energy Corporation and Stephen P. Dickson, dated December 29, 2008. (Exhibit 10.32 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.23*	Amended and Restated Non-Compete and Special Severance Tax Protection Agreement between Wisconsin Energy Corporation and Stephen P. Dickson, effective as of January 1, 2008. (Exhibit 10.33 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.24*	Letter Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q (File No. 001-09057).)** See Note.

	10.25*	Letter Agreement by between Wisconsin Energy Corporation and Joseph Kevin Fletcher, dated as of August 17, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/11 Form 10-Q (File No. 001-09057).)** See Note.

	10.26*	1993 Omnibus Stock Incentive Plan, amended and restated effective as of May 5, 2011, as approved by Wisconsin Energy Corporation's stockholders at its 2011 annual meeting of stockholders. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/11 Form 10-Q (File No. 001-09057).)** See Note.

	10.27*	2005 Terms and Conditions Governing Non-Qualified Stock Option Award under 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/28/04 Form 8-K (File No. 001-09057).)** See Note.

	10.28*	Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/07 Form 10-Q (File No. 001-09057).)** See Note.

	10.29*	Terms and Conditions Governing Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan, approved December 1, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/01/10 Form 8-K (File No. 001-09057).)** See Note.

	10.30*	Wisconsin Energy Corporation Terms and Conditions Governing Director Restricted Stock Award under the 1993 Omnibus Stock Incentive Plan, amended and restated effective May 5, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 01/19/12 Form 8-K (File No. 001-09057).)** See Note.

	10.31*	Wisconsin Energy Corporation Performance Unit Plan, amended and restated effective as of January 1, 2015. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.

	10.32*	Form of Award of Performance Units under the Wisconsin Energy Corporation Performance Unit Plan. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/06/04 Form 8-K (File No. 001-09057).)** See Note.



	E-4	Wisconsin Electric Power Company



	2014 Form 10-K



Number	Exhibit


	10.33*	Wisconsin Energy Corporation Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.

	10.34*	Wisconsin Energy Corporation Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibous Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.

	10.35*	Port Washington I Facility Lease Agreement between Port Washington Generating Station LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.7 to Wisconsin Electric's 06/30/03 Form 10-Q.)

	10.36*	Port Washington II Facility Lease Agreement between Port Washington Generating Station LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.8 to Wisconsin Electric's 06/30/03 Form 10-Q.)

	10.37*	Elm Road I Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

	10.38*	Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

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

	10.40*	Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC, dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K (File No. 001-09057).)

	Note: Two asterisks (**) identify management contracts and executive compensation plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of Form 10-K.

21	Subsidiaries of the registrant

	21.1	Subsidiaries of Wisconsin Electric Power Company.

23	Consents of experts and counsel

	23.1	Deloitte & Touche LLP - Milwaukee, WI, Consent of Independent Registered Public Accounting Firm.



	E-5	Wisconsin Electric Power Company



	2014 Form 10-K



Number	Exhibit

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



	E-6	Wisconsin Electric Power Company