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, 2013

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

001-09057	WISCONSIN ENERGY CORPORATION	39-1391525
	(A Wisconsin Corporation)
	231 West Michigan Street
	P.O. Box 1331
	Milwaukee, WI 53201
	(414) 221-2345

Securities Registered Pursuant to Section 12(b) of the Act:
	Name of Each Exchange
Title of Each Class	on Which Registered
Common Stock, $.01 Par Value	New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:     None

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

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 [X]	Accelerated filer [  ]
Non-accelerated filer [  ] (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]

The aggregate market value of the common stock of Wisconsin Energy Corporation held by non-affiliates was $9.3 billion based upon the reported closing price of such securities as of June 30, 2013.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (January 31, 2014):

Common Stock, $.01 Par Value, 225,946,296 shares outstanding

Documents Incorporated by Reference

Portions of Wisconsin Energy Corporation's Definitive Proxy Statement on Schedule 14A for its Annual Meeting of Stockholders, to be held on May 2, 2014, are incorporated by reference into Part III hereof.

2013 Form 10-K

WISCONSIN ENERGY CORPORATION

FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2013

_______________________________________

TABLE OF CONTENTS
Item	Page
PART I
1.   Business	10
1A. Risk Factors	25
1B. Unresolved Staff Comments	34
2.    Properties	34
3.    Legal Proceedings	36
4.    Mine Safety Disclosures	37
Executive Officers of the Registrant	38

PART II
5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases        of Equity Securities			39
6.    Selected Financial Data			41
7.    Management's Discussion and Analysis of Financial Condition and Results of Operations			42
7A. Quantitative and Qualitative Disclosures About Market Risk			71
8.    Financial Statements and Supplementary Data			72
	Consolidated Income Statements		72
	Consolidated Balance Sheets -- Assets		73
	Consolidated Balance Sheets -- Capitalization and Liabilities		74
	Consolidated Statements of Cash Flows		75
	Consolidated Statements of Common Equity		76
	Consolidated Statements of Capitalization		77
	Notes to Consolidated Financial Statements		78
	Note A	Summary of Significant Accounting Policies	78
	Note B	Recent Accounting Pronouncements	82
	Note C	Regulatory Assets and Liabilities	82
	Note D	Asset Sales, Divestitures and Discontinued Operations	83
	Note E	Asset Retirement Obligations	84
	Note F	Variable Interest Entities	84
	Note G	Income Taxes	84
	Note H	Common Equity	87
	Note I	Preferred Stock	91
	Note J	Long-Term Debt and Capital Lease Obligations	91
	Note K	Short-Term Debt	93
	Note L	Derivative Instruments	93
	Note M	Fair Value Measurements	95
	Note N	Benefits	97

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2013 Form 10-K

TABLE OF CONTENTS - (Cont'd)
Item			Page
	Note O	Segment Reporting	102
	Note P	Related Parties	104
	Note Q	Commitments and Contingencies	104
	Note R	Supplemental Cash Flow Information	106
	Reports of Independent Registered Public Accounting Firm		107
9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			109
9A.  Controls and Procedures			109
9B.  Other Information			109
PART III
10.  Directors, Executive Officers and Corporate Governance of the Registrant			110
11.  Executive Compensation			110
12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder        Matters			110
13.  Certain Relationships and Related Transactions, and Director Independence			111
14.  Principal Accountant Fees and Services			111
PART IV
15.  Exhibits and Financial Statement Schedules			112
Schedule I - Condensed Parent Company Financial Statements			113
Schedule II - Valuation and Qualifying Accounts			118
Signatures			119
Exhibit Index			E-1

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2013 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 Subsidiaries
We Power	W.E. Power, LLC
Wisconsin Electric	Wisconsin Electric Power Company
Wisconsin Gas	Wisconsin Gas LLC
Significant Assets
MCPP	Milwaukee County Power Plant
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 Subsidiaries and Affiliates
ATC	American Transmission Company LLC
DATC	Duke-American Transmission Company
ERGSS	Elm Road Generating Station Supercritical, LLC
WECC	Wisconsin Energy Capital Corporation
Wispark	Wispark LLC
Wisvest	Wisvest LLC
Federal and State Regulatory Agencies
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MDEQ	Michigan Department of Environmental Quality
MPSC	Michigan Public Service Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Environmental Terms
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
MATS	Mercury and Air Toxics Standards
NAAQS	National Ambient Air Quality Standards
NOV	Notice of Violation

5 Wisconsin Energy Corporation

2013 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:
NOx	Nitrogen Oxide
PM2.5	Fine Particulate Matter
RACT	Reasonably Available Control Technology
SIP	State Implementation Plan
SO2	Sulfur Dioxide
Other Terms and Abbreviations
AQCS	Air Quality Control System
ARRs	Auction Revenue Rights
Bechtel	Bechtel Power Corporation
Compensation Committee	Compensation Committee of the Board of Directors
CPCN	Certificate of Public Convenience and Necessity
ERISA	Employee Retirement Income Security Act of 1974
Exchange Act	Securities Exchange Act of 1934, as amended
Fitch	Fitch Ratings
FTRs	Financial Transmission Rights
GCRM	Gas Cost Recovery Mechanism
Junior Notes	Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067
LMP	Locational Marginal Price
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
PUHCA 2005	Public Utility Holding Company Act of 2005
RCC	Replacement Capital Covenant dated May 11, 2007
RTO	Regional Transmission Organization
S&P	Standard & Poor's Ratings Services
SSR	System Support Resource
Treasury Grant	Section 1603 Renewable Energy Treasury Grant
WPL	Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp.
Wolverine	Wolverine Power Supply Cooperative, Inc.
Measurements
Btu	British Thermal Unit(s)
Dth	Dekatherm(s) (One Dth equals one million Btu)
GWh	Gigawatt-hour(s) (One GWh equals one thousand MWh)
kW	Kilowatt(s) (One kW equals one thousand Watts)
kWh	Kilowatt-hour(s)
MW	Megawatt(s) (One MW equals one million Watts)
MWh	Megawatt-hour(s)
Watt	A measure of power production or usage

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2013 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:
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
ASU	Accounting Standards Update
CWIP	Construction Work in Progress
GAAP	Generally Accepted Accounting Principles
OPEB	Other Post-Retirement Employee Benefits

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2013 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, dividend payout ratios, 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," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets" or similar terms or variations of these terms.

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

• Factors affecting utility operations such as catastrophic weather-related or terrorism-related damage; cyber-security threats and disruptions to our technology network; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; unanticipated changes in the cost or availability of materials needed to operate 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, including recovery of costs associated with environmental compliance, renewable generation, transmission service, distribution system upgrades, fuel and the Midcontinent Independent System Operator, Inc. (MISO) Energy Markets, as well as any costs incurred as a result of customers moving to an alternative electric supplier.

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

• Our ability to mitigate the impact of Michigan customers switching to an alternative electric supplier, including the receipt of adequate System Support Resource (SSR) payments.

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

• The impact of recent and future federal, state and local legislative and regulatory changes, including any changes in rate-setting policies or procedures; regulatory initiatives regarding deregulation and restructuring of the electric and/or gas utility industry; transmission or distribution system operation and/or administration

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION - (Cont'd) 2013 Form 10-K

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

• Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances.

• Current and future litigation, regulatory investigations, proceedings or inquiries, including Federal Energy Regulatory Commission (FERC) matters and Internal Revenue Service (IRS) and state tax audits and other tax matters.

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

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

• Inflation rates.

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

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

• 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.

• Potential strategic business opportunities, including acquisitions and/or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to us.

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

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

• Changes to the legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law.

• 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 Energy Corporation

2013 Form 10-K

PART I

ITEM 1. BUSINESS

INTRODUCTION

Wisconsin Energy Corporation was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. Unless qualified by their context when used in this document, the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.

We conduct our operations primarily in two reportable segments: a utility energy segment and a non-utility energy segment. Our primary subsidiaries are Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas LLC (Wisconsin Gas) and W.E. Power, LLC (We Power).

Utility Energy Segment:   Our utility energy segment consists of Wisconsin Electric and Wisconsin Gas, operating together under the trade name of "We Energies." We Energies serves approximately 1,128,300 electric customers in Wisconsin and the Upper Peninsula of Michigan. We Energies serves approximately 1,079,800 gas customers in Wisconsin and approximately 445 steam customers in metropolitan Milwaukee, Wisconsin.

Non-Utility Energy Segment:   Our non-utility energy segment consists primarily of We Power, which owns and leases to Wisconsin Electric generation plants constructed as part of our Power the Future (PTF) strategy. All four of the plants constructed as part of PTF have been placed in service. Port Washington Generating Station Unit 1 (PWGS 1) and Port Washington Generating Station Unit 2 (PWGS 2) are being leased to Wisconsin Electric under long-term leases that run for 25 years. Oak Creek expansion Unit 1 (OC 1) and Oak Creek expansion Unit 2 (OC 2) are being leased to Wisconsin Electric under long-term leases that run for 30 years.

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.

Our annual and periodical filings with the SEC are available, free of charge, through our 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 ENERGY SEGMENT

ELECTRIC UTILITY OPERATIONS

Our electric utility operations consist of the electric operations of Wisconsin Electric. Wisconsin Electric, which is the largest electric utility in the state of Wisconsin, generates and distributes electric energy in a territory that includes southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and the Upper Peninsula of Michigan.

Wisconsin Electric participates in the 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 sales to all classes of customers, including distribution sales to those customers who switched to an alternative electric supplier, totaled approximately 33.0 million MWh during 2013 and approximately 30.3 million MWh during 2012. We had approximately 1,128,300 electric customers as of December 31, 2013 and 1,125,700 electric customers as of December 31, 2012.

Wisconsin Electric is 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

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ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities. Wisconsin Electric also sells wholesale electric power within the MISO Energy Markets.

Electric Sales Growth:   Our service territory experienced slightly declining retail sales in 2013 as positive customer growth was more than offset by reduced use per customer. 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 annual rates 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 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.

The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition in Item 7.

Sales to Wholesale Customers:   During 2013, we sold wholesale electric power to two Regional Transmission Organizations (RTOs), five rural cooperatives, and four municipal joint action agencies located in the states of Wisconsin and Michigan. Our wholesale electric energy sales were also made to eight other public utilities and power marketers throughout the region under rates approved by FERC. Wholesale sales accounted for approximately 19.7% of our total electric energy sales and 8.7% of total electric operating revenues during 2013, compared with 10.6% of total electric energy sales and 6.2% of total electric operating revenues during 2012.

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 2013 and expect to have adequate capacity to meet the planning reserve margin requirements during 2014. 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, Wisconsin Electric attempts 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.

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

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ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

electricity to our customers from power plants that we own. 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)
	2013	2012	2011
Coal	3,822	3,828	3,904
Natural Gas - Combined Cycle	1,082	1,090	1,090
Natural Gas/Oil - Peaking Units (b)	962	962	967
Renewables (c)	155	107	80
Total	6,021	5,987	6,041

(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.

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2013, as well as an estimate for 2014:

	Estimate		Actual
	2014		2013		2012		2011
Coal	56.0	%	53.6	%	43.0	%	54.2	%
Natural Gas - Combined Cycle	6.6	%	10.1	%	15.9	%	6.6	%
Renewables	4.1	%	3.3	%	3.0	%	2.0	%
Natural Gas/Oil-Peaking Units	0.1	%	0.2	%	0.7	%	0.1	%
Net Generation	66.8	%	67.2	%	62.6	%	62.9	%
Purchased Power	33.2	%	32.8	%	37.4	%	37.1	%
Total	100.0	%	100.0	%	100.0	%	100.0	%

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

	2013		2012		2011
Coal	$	27.97	$	30.71	$	29.78
Natural Gas - Combined Cycle	$	32.22	$	23.62	$	38.02
Natural Gas/Oil - Peaking Units	$	83.95	$	53.40	$	119.83
Purchased Power	$	43.74	$	41.92	$	42.79

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.

Natural gas costs have been volatile. 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.

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ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

Coal-Fired Generation

Coal Supply:   We diversify the coal supply for our power plants by purchasing coal from mines in Wyoming, Pennsylvania and Montana, as well as from various other states. During 2014, 94% of our projected coal requirements of 10.8 million tons are under contracts which are not tied to 2014 market pricing fluctuations. At the end of 2013, our coal-fired generation consisted of six operating plants with a dependable capability of approximately 3,822 MW.

The annual tonnage amounts contracted for 2014 through 2016 are as follows:

Year	Annual Tonnage
	(Thousands)
2014	10,157
2015	7,180
2016	3,920

These figures exclude the Oak Creek expansion projected coal requirements and allocated commitments of the plant's co-owners.

Coal Deliveries:   Approximately 98% of our 2014 coal requirements are expected to be delivered by Wisconsin Electric-owned or leased unit trains. 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. Coal from a Montana mine is also transported via rail to Lake Michigan transfer docks and delivered by lake vessel to the Milwaukee harbor for Milwaukee-based power plants. 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.

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.

Wolverine Joint Ownership Agreement:   In November 2012, we entered into a joint ownership agreement with Wolverine Power Supply Cooperative, Inc. (Wolverine) regarding PIPP, whereby Wolverine would pay for the installation of the air quality control systems at PIPP and receive a minority undivided ownership interest in the plant in return.

However, in light of the recent loss of retail electric customers in Michigan due to that state's alternative electric supplier program (see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Restructuring in Michigan in Item 7), the two parties decided to terminate the joint venture agreement in December 2013. We are currently evaluating options for the long-term future of PIPP.

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.

Natural Gas-Fired Generation

Our natural gas-fired generation consists of four operating plants with a dependable capability of approximately 1,864 MW as of December 31, 2013.

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.

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ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

We have a PSCW-approved hedging 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 Valley Power Plant (VAPP). Our oil-fired generation had a dependable capability of approximately 180 MW as of December 31, 2013. 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:   Wisconsin Electric's 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, 2013. 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 on November 8, 2013. Wood waste and wood shavings are used to produce approximately 50 MW of renewable electricity and also support Domtar's sustainable papermaking operations. The final cost of completing this project was $269.0 million, excluding Allowance for Funds Used During Construction (AFUDC).

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, 2013 with unaffiliated parties for the next five years:

Year	MW
2014	1,267
2015	1,267
2016	1,267
2017	1,267
2018	1,267

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.

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 Wisconsin Electric, 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 Wisconsin Electric is a non-transmission owning member and customer of MISO. We owned

14 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

approximately 26.2% of ATC as of December 31, 2013 and 2012. 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. DATC has proposed nine new transmission lines, located in five Midwestern states, to support MISO's and PJM Interconnection's transmission expansion plans. These projects are subject to the receipt of all necessary approvals. In addition, in April 2013, DATC acquired a 72% interest in California's Path 15 transmission line.

MISO:   In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which includes the bid-based energy markets and the 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 Central region. We do not expect these changes to have a material impact on our allocation of MISO costs. 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 Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

Electric Utility Operating Statistics

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

SELECTED CONSOLIDATED ELECTRIC UTILITY OPERATING DATA
Year Ended December 31	2013		2012		2011		2010		2009
Operating Revenues (Millions)
Residential	$	1,208.6	$	1,163.9	$	1,159.2	$	1,114.3	$	977.6
Small Commercial/Industrial	1,048.0		1,013.6		1,006.9		922.2		860.3
Large Commercial/Industrial	711.9		744.3		763.7		677.1		599.4
Other - Retail	23.4		22.8		22.9		21.9		21.2
Total Retail Revenues	2,991.9		2,944.6		2,952.7		2,735.5		2,458.5
Wholesale - Other	143.7		144.4		154.0		134.6		116.7
Resale - Utilities	143.2		53.4		69.5		40.4		47.5
Other Operating Revenues	28.4		51.5		35.1		25.8		62.3
Total	3,307.2		3,193.9		3,211.3		2,936.3		2,685.0
Electric Customer Choice (a)	1.5		—		—		—		—
Total Operating Revenues, including customer choice	$	3,308.7	$	3,193.9	$	3,211.3	$	2,936.3	$	2,685.0
MWh Sales (Thousands)
Residential	8,141.9		8,317.7		8,278.5		8,426.3		7,949.3
Small Commercial/Industrial	8,860.4		8,860.0		8,795.8		8,823.3		8,571.6
Large Commercial/Industrial	8,673.4		9,710.7		9,992.2		9,961.5		9,140.3
Other - Retail	152.3		154.8		153.6		155.3		156.5
Total Retail Sales	25,828.0		27,043.2		27,220.1		27,366.4		25,817.7
Wholesale - Other	1,953.5		1,566.6		2,024.8		2,004.6		1,529.4
Resale - Utilities	4,382.7		1,642.4		2,065.7		1,103.8		1,548.9
Total Electric Sales	32,164.2		30,252.2		31,310.6		30,474.8		28,896.0
Electric Customer Choice (a)	813.0		—		—		—		—
Total MWh Delivered	32,977.2		30,252.2		31,310.6		30,474.8		28,896.0
Customers - End of Year (Thousands)
Residential	1,010.5		1,008.2		1,005.5		1,003.6		1,001.2
Small Commercial/Industrial	114.6		114.3		113.8		113.5		113.1
Large Commercial/Industrial	0.7		0.7		0.7		0.7		0.7
Other	2.5		2.5		2.5		2.4		2.4
Total Customers	1,128.3		1,125.7		1,122.5		1,120.2		1,117.4
Customers - Average (Thousands)	1,126.9		1,123.8		1,121.0		1,118.7		1,115.5
Degree Days (b)
Heating (6,580 Normal)	7,233		5,704		6,633		6,183		6,825
Cooling (730 Normal)	688		1,041		793		944		475

(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.

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ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

GAS UTILITY OPERATIONS

Our gas utility operations consist of Wisconsin Gas and the gas operations of Wisconsin Electric, both operating under the trade name of "We Energies." 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. We are the largest natural gas distribution utility in Wisconsin, and we operate throughout the state, including the City of Milwaukee, west and south of the City of Milwaukee, the Appleton area and large areas of both central and western 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 2,442.8 million therms during 2013, a 9.9% increase compared with 2012. As of December 31, 2013, we were transporting gas for approximately 1,700 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 43.1% of the total volumes delivered during 2013, 51.3% during 2012 and 41.8% during 2011. We had approximately 1,079,800 and 1,074,000 gas customers as of December 31, 2013 and 2012, respectively. Our peak daily send-out during 2013 was 1,701,421 Dth on January 21, 2013.

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 and fabricated metal products. Fuel used for Wisconsin Electric's electric generation represents our largest transportation customer. Gas therms delivered to Wisconsin Electric for electric generation represents 10.4%, 17.2% and 8.3% of the total volumes delivered during 2013, 2012 and 2011, respectively.

Gas Deliveries Growth:   We currently forecast total retail therm deliveries (excluding natural gas deliveries for generation) to be between flat and 0.5% growth over the five-year period ending December 31, 2018, as we expect new customer additions to increase and offset an anticipated slight decline in average use per customer. This forecast reflects a current year weather normalized sales level and normal weather.

Western Gas Lateral:   We are projecting the need for additional capacity for our natural gas distribution network in the western part of Wisconsin to address reliability and meet customer demand. We filed an application with the PSCW seeking approval to construct a new natural gas lateral on March 28, 2013. The anticipated cost of the initial phase of this project is approximately $150 million to $170 million, excluding AFUDC.

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.

17 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

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.

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 levels at approximately 35% of forecasted winter demand. 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 firm daily transportation and storage capacity entitlements from pipelines and other service providers under 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 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 Wisconsin Electric and Wisconsin Gas, 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 the Wisconsin Electric and Wisconsin Gas approved Gas Cost Recovery Mechanisms (GCRMs). During 2013, we continued to participate in the secondary markets. See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 for information on the GCRMs.

Spot Market Gas Supply:   We expect to continue to make gas purchases in the 30-day spot market as price 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 both Wisconsin Electric and Wisconsin Gas to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through their respective GCRMs. Hedge targets (volumes) are provided annually to the PSCW as part of each company's 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 GCRMs.

18 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

Gas Utility Operating Statistics

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

SELECTED CONSOLIDATED GAS UTILITY OPERATING DATA
Year Ended December 31	2013			2012		2011		2010		2009
Operating Revenues (Millions)
Residential	$	712.6		$	612.0	$	737.4	$	754.2	$	856.6
Commercial/Industrial	347.2			289.7		369.9		373.1		442.9
Interruptible	8.9			7.3		9.4		11.8		11.9
Total Retail Gas Sales	1,068.7			909.0		1,116.7		1,139.1		1,311.4
Transported Gas	50.8			49.4		49.2		48.0		44.8
Other Operating Revenues	(5.8		)	4.2		15.3		3.1		11.7
Total Operating Revenues	$	1,113.7		$	962.6	$	1,181.2	$	1,190.2	$	1,367.9
Therms Delivered (Millions)
Residential	872.0			676.4		776.8		741.2		803.4
Commercial/Industrial	499.9			390.6		461.7		429.6		479.4
Interruptible	18.1			14.6		16.0		19.4		19.1
Total Retail Gas Sales	1,390.0			1,081.6		1,254.5		1,190.2		1,301.9
Transported Gas	1,052.8			1,140.4		899.6		914.9		882.0
Total Therms Delivered	2,442.8			2,222.0		2,154.1		2,105.1		2,183.9
Customers - End of Year (Thousands)
Residential	985.7			980.3		975.2		971.7		967.7
Commercial/Industrial	92.3			92.0		91.5		91.3		91.1
Interruptible	0.1			0.1		0.1		0.1		0.1
Transported Gas	1.7			1.6		1.4		1.4		1.3
Total Customers	1,079.8			1,074.0		1,068.2		1,064.5		1,060.2
Customers - Average (Thousands)	1,074.9			1,068.9		1,064.1		1,060.2		1,055.6
Degree Days (a)
Heating (6,580 Normal)	7,233			5,704		6,633		6,183		6,825

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

OTHER UTILITY OPERATIONS

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, a coal-fired cogeneration facility. 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 2013, the steam utility had $39.6 million of operating revenues from the sale of 2,750 million pounds of steam compared with $34.3 million of operating revenues from the sale of 2,449 million pounds of steam during 2012. As of December 31, 2013 and 2012, steam was used by approximately 445 customers and 460 customers, respectively, for processing, space heating, domestic hot water and humidification.

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ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

UTILITY RATE MATTERS

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

NON-UTILITY ENERGY SEGMENT

Our non-utility energy segment consists primarily of generating plants constructed as part of our PTF strategy. As of December 31, 2013, our PTF assets represented virtually all of our non-utility energy segment assets.

We Power

We Power, through wholly owned subsidiaries, has designed and built approximately 2,320 MW of new generation in Wisconsin, which is being leased to Wisconsin Electric under long-term leases. This generation consists of approximately 1,230 MW of capacity from OC 1 and OC 2, and 1,090 MW of capacity from PWGS 1 and PWGS 2. PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively. In November 2005, two unaffiliated entities collectively purchased an ownership interest of approximately 17%, or 200 MW, in OC 1 and OC 2. Similar to the generating capacity at PWGS 1 and PWGS 2, We Power owns the remaining generating capacity at OC 1 and OC 2.

Our PTFstrategy was designed to address Wisconsin Electric's electric supply needs by increasing the electric generating capacity in Wisconsin while allowing us to maintain a diversified fuel mix, by including both new coal-fired plants and natural-gas fired plants. Because of the significant investment necessary to construct these generating units, we constructed the plants under Wisconsin's Leased Generation Law, which became effective in August 2001 and allows a non-utility affiliate to construct an electric generating facility and lease it to the public utility. The law allows a public utility that has entered into a lease approved by the PSCW to recover fully in its retail electric rates that portion of any payments under the lease that the PSCW has allocated to the public utility's Wisconsin retail electric service, and all other costs that are prudently incurred in the public utility's operation and maintenance of the electric generating facility allocated to the utility's Wisconsin retail electric service. In addition, the PSCW may not modify or terminate a lease it has approved under the Leased Generation Law except as specifically provided in the lease or the PSCW's order approving the lease. This law effectively created regulatory certainty in light of the significant investment being made to construct the units. All four PTF units were constructed under leases approved by the PSCW. For additional background information on our PTF strategy, see Management's Discussion and Analysis of Financial Condition and Results of Operations - Corporate Developments - Corporate Strategy - Power the Future Strategy and - Factors Affecting Results, Liquidity and Capital Resources - Power the Future in Item 7 of our Form 10-K for the year ended December 31, 2007.

For further information about our PTF strategy, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7.

Wisvest LLC

Wisvest was originally formed to develop, own and operate electric generating facilities and to invest in other energy-related entities. As a result of the change in corporate strategy to focus on our PTF strategy, Wisvest discontinued its development activity. As of December 31, 2013, Wisvest's sole operating asset and investment is Wisvest Thermal Energy Services, which provides chilled water services to the Milwaukee Regional Medical Center.

OTHER NON-UTILITY OPERATIONS

Wispark LLC and Bostco LLC

Wispark and Bostco develop and invest in real estate, and combined had $83.4 million in real estate holdings as of December 31, 2013. Wispark has developed several business parks and other commercial real estate projects, primarily in southeastern Wisconsin.

20 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

REGULATION

Wisconsin Energy Corporation

Wisconsin Energy is a holding company, but is exempt from the requirements of the Public Utility Holding Company Act of 2005 (PUHCA 2005).

Non-Utility Asset Cap:   Pursuant to the non-utility asset cap provisions of Wisconsin's public utility holding company law, the sum of certain assets of all non-utility affiliates in a holding company system may not exceed 25% of the assets of all public utility affiliates. However, among other items, the law exempts energy-related assets, including the generating plants constructed by We Power as part of our PTF strategy, from being counted against the asset cap provided that they are employed in qualifying businesses. As a result of these exemptions, our non-utility assets are significantly below the non-utility asset cap as of December 31, 2013.

Utility Energy Segment

Wisconsin Electric is a holding company because of its ownership interest in ATC, but is exempt from the requirements of PUHCA 2005.

Wisconsin Electric is 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 Wisconsin Electric. 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.

Wisconsin Electric and Wisconsin Gas 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. Wisconsin Electric is also subject to the regulation of the PSCW as to certain levels of short-term debt obligations. Wisconsin Electric is 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 Wisconsin Electric's hydroelectric facilities are regulated by FERC. Wisconsin Electric is 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 for our regulated entities, see Utility Rates and Regulatory Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7.

21 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

The following table compares our utility energy segment operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2013:

	2013				2012				2011
	Amount		Percent		Amount		Percent		Amount		Percent
	(Millions of Dollars)
Electric
Wisconsin - Retail	$	2,874.8	86.9	%	$	2,808.4	87.9	%	$	2,775.8	86.4	%
Michigan - Retail	147.0		4.4	%	187.8		5.9	%	212.0		6.6	%
FERC - Wholesale	286.9		8.7	%	197.7		6.2	%	223.5		7.0	%
Total	3,308.7		100.0	%	3,193.9		100.0	%	3,211.3		100.0	%
Gas - Wisconsin - Retail	1,113.7		100.0	%	962.6		100.0	%	1,181.2		100.0	%
Steam - Wisconsin - Retail	39.6		100.0	%	34.3		100.0	%	39.0		100.0	%
Total Utility Operating Revenues	$	4,462.0			$	4,190.8			$	4,431.5

The percentage of revenues regulated by the MPSC is likely to decline in the future.

The operations of Wisconsin Electric and Wisconsin Gas 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.

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 must 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, 2013, 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%. In addition, under this Act, 1.2% of utilities' annual operating revenues were required to be used to fund energy conservation programs in 2013. The funding required by Act 141 for 2014 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 -- Utility Rates and Regulatory Matters - Renewables, Efficiency and Conservation in Item 7.

Non-Utility Energy Segment

We Power was formed to design, construct, own and lease the new generating capacity in our PTF strategy. We Power owns the interests in the companies that constructed this new generating capacity (collectively, the We Power project companies). These facilities are being leased on a long-term basis to Wisconsin Electric. We Power received determinations from FERC that upon the transfer of the facilities by lease to Wisconsin Electric, the We Power project companies are not deemed public utilities under the Federal Power Act and thus are not subject to FERC's jurisdiction.

Environmental permits necessary for operating the facilities are the responsibility of the operating entity, Wisconsin Electric.

22 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

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 by Wisconsin Electric of approximately $24.7 million in 2013 compared with $64.1 million in 2012. Expenditures incurred during 2013 and 2012 primarily included costs associated with the installation of pollution abatement facilities at Wisconsin Electric's power plants. These expenditures are expected to be approximately $2.3 million during 2014. Operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $92.9 million and $82.6 million during 2013 and 2012, 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:

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 Wisconsin Electric 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.

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.

23 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2013 Form 10-K

Employees:As of December 31, 2013, we had the following number of employees:

	Total Employees	Represented Employees
Utility Energy Segment
Wisconsin Electric	3,893	2,517
Wisconsin Gas	407	280
Total	4,300	2,797
Non-Utility Energy Segment	—	—
Other	3	—
Total Employees	4,303	2,797

The employees represented under labor agreements were with the following bargaining units as of December 31, 2013:

	Number of Employees	Expiration Date of Current Labor Agreement
Wisconsin Electric
Local 2150 of International Brotherhood of Electrical Workers	1,730	August 15, 2017
Local 420 of International Union of Operating Engineers	539	September 30, 2017
Local 2006 Unit 1 of United Steel Workers	142	April 30, 2017
Local 510 of International Brotherhood of Electrical Workers	106	October 31, 2016
Total Wisconsin Electric	2,517
Wisconsin Gas
Local 2150 of International Brotherhood of Electrical Workers	85	August 15, 2017
Local 2006 Unit 1 of United Steel Workers	192	April 30, 2017
Local 2006 Unit 3 of United Steel Workers	3	February 29, 2016
Total Wisconsin Gas	280
Total Represented Employees	2,797

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2013 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, Wisconsin Electric's 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 regulated energy segment, approximately 87% of our 2013 electric revenues were regulated by the PSCW, 4% 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.

Wisconsin Electric and Wisconsin Gas 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

25 Wisconsin Energy Corporation

ITEM 1A. RISK FACTORS - (Cont'd) 2013 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. In addition, the EPA has proposed rules governing cooling water intake structures at our power plants and 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. The U.S. Court of Appeals for the D.C. Circuit vacated the CSAPR; however, the EPA successfully petitioned the United States Supreme Court, who heard the case in December 2013. A decision is expected by June 2014. Therefore, there is still substantial 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. We expect that additional environmental controls will be required at PIPP to meet the new environmental standards, and are currently analyzing several environmental compliance options.

In addition, 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. 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 further 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. The WDNR has issued a Notice of Violation (NOV) to Wisconsin Electric alleging violations of certain environmental rules at our Paris Generating Station (PSGS). An adverse outcome in these matters could require capital expenditures that cannot be determined at this time and could possibly require payment of penalties.

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.

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ITEM 1A. RISK FACTORS - (Cont'd) 2013 Form 10-K

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.

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

In June 2012, the U.S. Court of Appeals for the D.C. Circuit upheld the EPA's authority to regulate greenhouse gas emissions. The EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. In September 2013, the EPA withdrew its 2012 proposed New Source Performance Standards greenhouse gas emissions rule, and issued new proposed rules with greenhouse gas limits for new fossil fueled power plants. The rule would not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines. Based upon currently available technology and the emission limits in the proposed rule, we believe that this rule, if promulgated, would effectively prohibit new conventional coal-fired power plants.

With respect to existing generating units, the EPA has indicated that it intends to issue a proposed rule in June 2014, a final rule by June 2015 and require State Implementation Plans (SIPs) to be submitted by June 30, 2016. Any such regulations may impact how we operate our existing facilities, particularly our fossil fueled power plants and new biomass facility, and could have a material adverse impact on our financial condition.

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

Despite the United States Supreme Court's decision in Connecticut v. American Electric Power Co., where the Court ruled that the plaintiffs in that litigation did not have standing to claim nuisance due to the release of greenhouse gas into the atmosphere by the defendants, states and environmental groups have lawsuits pending against electric utilities and others to force reductions in greenhouse gas emissions based upon their contribution to the alleged public nuisance of climate change.

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

We may face significant costs if coal combustion products are regulated as hazardous waste.

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. If coal combustion products are classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program.

If coal combustion products are classified as hazardous waste and we terminate our coal combustion products utilization program, we could be required to dispose of the coal combustion products at a significant cost to the Company, which could adversely impact our results of operations and financial condition. We anticipate that the EPA could take action on this matter by the end of 2014.

27 Wisconsin Energy Corporation

ITEM 1A. RISK FACTORS - (Cont'd) 2013 Form 10-K

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

Wisconsin Electric is 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 and physical and cybersecurity assets. Compliance with the mandatory reliability standards could subject Wisconsin Electric to higher operating costs. While Wisconsin Electric passed the cybersecurity and operational audits mandated by the North American Electric Reliability Corporation in 2013, if it were ever found to be in noncompliance with the mandatory reliability standards it could be subject to sanctions, including substantial monetary penalties.

Energy conservation and rate increases could negatively impact financial results.

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. In addition, Wisconsin and Michigan have adopted energy efficiency targets to reduce energy consumption by certain dates. To the extent there is any regulatory lag to adjust rates as a result of reduced sales from effective conservation measures, these measures 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.

Provisions of the Wisconsin Utility Holding Company Act limit our ability to invest in non-utility businesses and could deter takeover attempts by a potential purchaser of our common stock that would be willing to pay a premium for our common stock.

Under the Wisconsin Utility Holding Company Act, we remain subject to certain restrictions that have the potential of limiting our diversification into non-utility businesses. Under the Act, the sum of certain assets of all non-utility affiliates in a holding company system generally may not exceed 25% of the assets of all public utility affiliates in the system, subject to certain exceptions.

In addition, the Act precludes the acquisition of 10% or more of the voting shares of a holding company of a Wisconsin public utility unless the PSCW has first determined that the acquisition is in the best interests of utility customers, investors and the public. This provision and other requirements of the Act may delay or reduce the likelihood of a sale or change of control of Wisconsin Energy. As a result, stockholders may be deprived of opportunities to sell some or all of their shares of our common stock at prices that represent a premium over market prices.

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 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 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

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ITEM 1A. RISK FACTORS - (Cont'd) 2013 Form 10-K

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.

We expect to spend an aggregate of between $3.2 billion and $3.5 billion during the period 2014 to 2018 on capital investments in our utility and non-utility energy business. 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; 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.

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 gas distribution facilities, as well as 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.

29 Wisconsin Energy Corporation

ITEM 1A. RISK FACTORS - (Cont'd) 2013 Form 10-K

Under our current rate structure, widespread adoption of distributed generation by our electric customers could increase the cost of service for our remaining customers. Increases in our rates could contribute to slower than anticipated customer growth and reduced demand for electricity, which could have an adverse impact on our financial condition, results of operations and cash flows.

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 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 information about our customers and employees.

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.

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. At this time, we are not aware of any cyber intrusion or security breach of our systems.

Internet-based attacks on critical U.S. energy infrastructure are occurring with more frequency. In February2013, the President issued an Executive Order providing for intelligence gathering and information exchange on cyber attacks and cyber threats to privately owned critical infrastructure. The framework is being developed jointly by the government and industry.

We continue to strengthen our electronic systems. However, as cyber attacks become more sophisticated, we may be required to incur significant costs to strengthen our information and electronic control systems from outside intrusions and/or to obtain insurance coverage related to the threat of such attacks.

We are a holding company and rely on the earnings of our subsidiaries to meet our financial obligations.

As a holding company with no operations of our own, our ability to meet our financial obligations and pay dividends on our common stock is dependent upon the ability of our subsidiaries to pay amounts to us, whether through dividends or other payments. The ability of our subsidiaries to pay amounts to us will depend on the earnings, cash flows, capital requirements and general financial condition of our subsidiaries and on regulatory limitations. Prior to distributing cash to Wisconsin Energy, our subsidiaries have financial obligations that must be satisfied, including among others, debt service and preferred stock dividends. Our subsidiaries also have dividend payment restrictions based on the terms of their outstanding preferred stock and regulatory limitations applicable to them. In addition, each of the bank back-up credit facilities for Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have specified total funded debt to capitalization ratios that must be maintained.

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.

30 Wisconsin Energy Corporation

ITEM 1A. RISK FACTORS - (Cont'd) 2013 Form 10-K

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 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 4.5% 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.

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. 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 committed bank credit agreements 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, a negative view of the utility industry, failures of financial institutions or other factors, our ability to implement our business plan could be limited which could materially and adversely affect our results of operations.

31 Wisconsin Energy Corporation

ITEM 1A. RISK FACTORS - (Cont'd) 2013 Form 10-K

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.

Our service territories have been impacted by the slow economy the country has been experiencing over the past several years. As a result, we expect to continue experiencing electric sales below historical trends.

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

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

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

The mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers have switched to an alternative electric supplier. Sales to these customers, including the mines, totaled 2,173.6 GWh, or 7.6% of our retail electric sales for the year ended December 31, 2012. Previously, the owner of the mines announced that they would shut down the Empire mine by the end of 2014 or beginning of 2015. We negotiated an SSR agreement with MISO and took other steps to mitigate the loss of these sales. Although the financial impact in future periods is uncertain, we currently estimate that these losses will not have a material impact on our consolidated financial statements in 2014.

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 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.

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ITEM 1A. RISK FACTORS - (Cont'd) 2013 Form 10-K

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

Wisconsin Electric burns natural gas in several of its peaking power plants and in PWGS 1 and 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. 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, Wisconsin Electric bears 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 its 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.

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 the hedging programs of Wisconsin Electric and Wisconsin Gas 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.

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

Our cost of providing pension and other post-retirement benefit 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

33 Wisconsin Energy Corporation

ITEM 1A. RISK FACTORS - (Cont'd) 2013 Form 10-K

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. We are facing rising medical costs for both active and retired employees. It is possible that these costs may increase at a rate that is significantly higher than anticipated. 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.

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.

34 Wisconsin Energy Corporation

ITEM 2. PROPERTIES - (Cont'd) 2013 Form 10-K

As of December 31, 2013, we owned the following generating assets:

		No. of	Dependable
		Generating	Capability
Name	Fuel	Units	In MW (a)
Coal-Fired Plants
South Oak Creek	Coal	4	990
Oak Creek Expansion	Coal	2	1,057
Presque Isle	Coal	5	344
Pleasant Prairie	Coal	2	1,188
Valley	Coal	2	236
Milwaukee County	Coal	3	7
Total Coal-Fired Plants		18	3,822
Natural Gas-Fired Plants
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		17	2,044
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	6,021

(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, 2013, we operated approximately 21,511 pole-miles of overhead distribution lines and 24,086 miles of underground distribution cable, as well as approximately 350 distribution substations and 290,999 line transformers.

As of December 31, 2013, our gas distribution system included approximately 20,967 miles of distribution and transmission mains connected at 181 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, Great Lakes Transmission Company, Viking Gas Transmission and Michigan Consolidated Gas Company. We have liquefied natural gas storage plants which convert and store, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plants have a send-out capability of 73,600 Dth per day. We also have propane air systems for peaking purposes. These propane air systems will provide approximately 2,960 Dth per day of supply to the system. Our gas distribution system consists almost entirely of plastic and coated steel pipe.

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.

35 Wisconsin Energy Corporation

ITEM 2. PROPERTIES - (Cont'd) 2013 Form 10-K

As of December 31, 2013, 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 NOV issued in connection with the replacement of certain turbine blades as part of maintenance performed on Units 1 and 4 at our PSGS.

Solvay Coke and Gas Site:  Wisconsin Electric and Wisconsin Gas have been identified as potentially responsible parties at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company of Wisconsin Electric owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site. In 2007, Wisconsin Electric, Wisconsin Gas 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. In-field investigation activities have commenced. Under the Administrative Settlement Agreement, neither Wisconsin Electric nor Wisconsin Gas admits to any liability for the site, waives any liability defenses, or commits to perform future site remedial activities. The companies' 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.

Edgewater Generating Unit 5:In December 2009, the EPA issued a NOV concerning several coal-fired power plants owned and operated by Wisconsin Power and Light Company (WPL), including Edgewater Generating Unit 5, of which Wisconsin Electric owned 25%. Due to its ownership interest at the time, Wisconsin Electric was named in the NOV. Although Wisconsin Electric sold its interest to WPL in March 2011, it retained its share of liability related to the NOV.

In April 2013, a complaint and consent decree were simultaneously lodged with the court in United States v. Wisconsin Power and Light Company, Madison Gas and Electric Company, Wisconsin Electric Power Company and Wisconsin Public Service Corporation, Case No. 13-cv-00266. The consent decree was entered by the court in June 2013, and resolved all allegations in the NOV related to Edgewater 5 and the other coal fired power plants owned and operated by WPL, as well as air permitting and opacity violations alleged by Sierra Club against WPL. Our share of the financial obligation associated with this consent decree was immaterial. This matter was fully closed when the consent decree was terminated as to Wisconsin Electric on October 1, 2013.

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.

36 Wisconsin Energy Corporation

ITEM 3. LEGAL PROCEEDINGS - (Cont'd) 2013 Form 10-K

UTILITY RATE MATTERS

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

OTHER MATTERS

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

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

37 Wisconsin Energy Corporation

2013 Form 10-K

EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages at December 31, 2013 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 63.

• 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 53.

• 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 55.

• 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 47.

• 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.

• NextEra Energy Resources -- Vice President from 2007 to 2009.

J. Patrick Keyes.   Age 48.

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

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

Allen L. Leverett.   Age 47.

• 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.

Susan H. Martin.   Age 61.

• 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.

38 Wisconsin Energy Corporation

EXECUTIVE OFFICERS OF THE REGISTRANT - (Cont'd) 2013 Form 10-K

• 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 our non-utility subsidiaries.

PART II

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

NUMBER OF COMMON STOCKHOLDERS

As of December 31, 2013, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had approximately 39,755 registered stockholders.

COMMON STOCK LISTING AND TRADING

Our common stock is listed on the New York Stock Exchange under the ticker symbol "WEC."

DIVIDENDS AND COMMON STOCK PRICES

Common Stock Dividends of Wisconsin Energy:Cash dividends on our common stock, as declared by the Board of Directors, are normally paid on or about the first day of March, June, September and December of each year. We review our dividend policy on a regular basis. Subject to any regulatory restrictions 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, earnings, financial condition and other requirements. For information regarding restrictions on the ability of our subsidiaries to pay us dividends, see Note H -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.

In January 2013, our Board of Directors affirmed our dividend policy that targets a dividend payout ratio of 60% in the year 2014, and approved a new dividend policy that targets a payout ratio that trends to 65-70% in 2017. In accordance with that policy, on January 17, 2013, the Board increased our quarterly dividend to $0.34 per share effective with the first quarter of 2013 dividend payment. On July 18, 2013, the Board of Directors increased our quarterly dividend to $0.3825 per share effective with the third quarter of 2013 dividend payment.

On January 16, 2014, the Board of Directors increased the quarterly dividend to $0.39 per share effective with the first quarter of 2014 dividend payment, which would result in annual dividends of $1.56 per share. In addition, the Board affirmed our dividend policy that targets a dividend payout ratio of 65-70% in 2017.

39 Wisconsin Energy Corporation

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES - (Cont'd) 2013 Form 10-K

Range of Wisconsin Energy Common Stock Prices and Dividends:

	2013						2012
Quarter	High		Low		Dividend		High		Low		Dividend
First	$	42.98	$	37.03	$	0.3400	$	35.35	$	33.62	$	0.30
Second	$	45.00	$	39.04	0.3400		$	40.00	$	34.54	0.30
Third	$	44.01	$	39.52	0.3825		$	41.48	$	37.46	0.30
Fourth	$	43.00	$	39.83	0.3825		$	38.93	$	36.01	0.30
Annual	$	45.00	$	37.03	$	1.4450	$	41.48	$	33.62	$	1.20

ISSUER PURCHASES OF EQUITY SECURITIES

2013	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (a)	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
					(Millions of Dollars)
October 1 - October 31	74,455	$	40.27	74,455	$	42.3
November 1 - November 30	482,156	$	41.56	482,156	$	22.2
December 1 - December 31	—	$	—	—	$	—
Total	556,611	$	41.38	556,611

(a) On May 5, 2011, Wisconsin Energy's Board of Directors authorized a share repurchase program for up to $300 million of our common stock which expired on December 31, 2013. We repurchased an aggregate of $277.8 million of our common stock under this program. On December 5, 2013, our Board of Directors authorized a new share repurchase program for up to $300 million of our common stock effective January 1, 2014 through December 31, 2017.

40 Wisconsin Energy Corporation

2013 Form 10-K

ITEM 6. SELECTED FINANCIAL DATA

WISCONSIN ENERGY CORPORATION
CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA
Financial	2013			2012			2011			2010			2009
Year Ended December 31
Net income - Continuing Operations (Millions)	$	577.4		$	546.3		$	512.8		$	454.4		$	375.7
Earnings per share - Continuing Operations
Basic	$	2.54		$	2.37		$	2.20		$	1.94		$	1.61
Diluted	$	2.51		$	2.35		$	2.18		$	1.92		$	1.59
Dividends per share of common stock	$	1.445		$	1.20		$	1.04		$	0.80		$	0.675
Operating revenues (Millions)
Utility energy	$	4,462.0		$	4,190.8		$	4,431.5		$	4,165.3		$	4,092.0
Non-utility energy	446.7			439.9			435.1			320.2			163.1
Eliminations and Other	(389.7		)	(384.3		)	(380.2		)	(283.0		)	(154.2		)
Total operating revenues	$	4,519.0		$	4,246.4		$	4,486.4		$	4,202.5		$	4,100.9
As of December 31 (Millions)
Total assets	$	14,769.4		$	14,285.0		$	13,862.1		$	13,059.8		$	12,697.9
Long-term debt (including current maturities) and capital lease obligations	$	4,705.4		$	4,865.9		$	4,646.9		$	4,405.4		$	4,171.5
Common Stock Closing Price	$	41.34		$	36.85		$	34.96		$	29.43		$	24.92
CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA
	(Millions of Dollars, Except Per Share Amounts) (a)
	March						June
Three Months Ended	2013			2012			2013			2012
Operating revenues	$	1,275.2		$	1,191.2		$	1,012.3		$	944.7
Operating income	$	321.0		$	295.7		$	229.5		$	222.6
Total net income	$	176.6		$	172.1		$	119.0		$	119.3
Earnings per share of common stock (b)
Basic	$	0.77		$	0.75		$	0.52		$	0.52
Diluted	$	0.76		$	0.74		$	0.52		$	0.51
	September						December
Three Months Ended	2013			2012			2013			2012
Operating revenues	$	1,053.2		$	1,039.3		$	1,178.3		$	1,071.2
Operating income	$	258.0		$	280.6		$	271.6		$	201.4
Total net income	$	137.5		$	156.1		$	144.3		$	98.8
Earnings per share of common stock (b)
Basic	$	0.61		$	0.68		$	0.64		$	0.43
Diluted	$	0.60		$	0.67		$	0.63		$	0.43

(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.

(b) Quarterly earnings per share may not total to the amounts reported for the year because the computation is based on the weighted average common shares outstanding during each quarter.

41 Wisconsin Energy Corporation

2013 Form 10-K

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

AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

INTRODUCTION

Wisconsin Energy Corporation is a diversified holding company with subsidiaries primarily in a utility energy segment and a non-utility energy segment. Unless qualified by their context, when used in this document the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.

Our utility energy segment primarily consists of Wisconsin Electric and Wisconsin Gas, both doing business under the trade name of "We Energies." We generate and distribute electricity in Wisconsin and the Upper Peninsula of Michigan and we distribute natural gas in Wisconsin. Our non-utility energy segment primarily consists of We Power, which primarily owns and leases to Wisconsin Electric electric power generating facilities constructed as part of our PTF strategy.

CORPORATE STRATEGY

Business Opportunities

We have three primary investment opportunities and earnings streams: our regulated utility business; our investment in ATC; and our generation plants within our non-utility energy segment.

Our regulated utility business primarily consists of electric generation assets and the electric and gas distribution assets that serve our electric and gas customers under the trade name of We Energies. We Energies operates under a traditional rate regulated cost of service environment. During 2013, our regulated utility earned $719.4 million of operating income. Over the next five years, we expect to invest between $3.1 billion and $3.3 billion in this business.

We have a 26.2% ownership interest in ATC, a MISO member company regulated by FERC. Our investment in ATC totaled $402.7 million as of December 31, 2013, and our 2013 pre-tax earnings from ATC totaled $68.5 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 $130 million in ATC as it continues to invest in transmission projects.

Our non-utility energy segment consists primarily of the four generation plants constructed as part of our PTF strategy. All four plants have been placed in service and are being leased to Wisconsin Electric under long-term leases that run for 25 years (PWGS 1 and PWGS 2) and 30 years (OC 1 and OC 2). We recognize revenues on a levelized basis over the life of the leases. Our operating income from our non-utility business totaled $367.1 million during 2013, and we expect comparable earnings from this segment in 2014. The PTF strategy was developed with the primary goal of constructing these power plants. Over the next five years, we do, however, expect to invest approximately $117 million in this segment on smaller capital projects, including the Oak Creek expansion fuel flexibility project. For additional information on this project, see Factors Affecting Results, Liquidity and Capital Resources -- Other Matters.

42 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

RESULTS OF OPERATIONS

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income for 2013, 2012 and 2011:

Wisconsin Energy Corporation	2013			2012			2011
	(Millions of Dollars)
Utility Energy	$	719.4		$	647.7		$	544.8
Non-Utility Energy	367.1			358.8			348.9
Corporate and Other	(6.4		)	(6.2		)	(6.4		)
Total Operating Income	1,080.1			1,000.3			887.3
Equity in Earnings of Transmission Affiliate	68.5			65.7			62.5
Other Income and Deductions, net	18.8			34.8			62.7
Interest Expense, net	252.1			248.2			235.8
Income from Continuing Operations Before Income Taxes	915.3			852.6			776.7
Income Tax Expense	337.9			306.3			263.9
Income from Continuing Operations	577.4			546.3			512.8
Income from Discontinued Operations, Net of Tax	—			—			13.4
Net Income	$	577.4		$	546.3		$	526.2
Diluted Earnings Per Share
Continuing Operations	$	2.51		$	2.35		$	2.18
Discontinued Operations	—			—			0.06
Total Diluted Earnings Per Share	$	2.51		$	2.35		$	2.24

An analysis of contributions to operating income by segment and a more detailed analysis of results follows.

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

The following table summarizes our utility energy segment's operating income during 2013, 2012 and 2011:

Utility Energy Segment	2013		2012		2011
	(Millions of Dollars)
Operating Revenues
Electric	$	3,308.7	$	3,193.9	$	3,211.3
Gas	1,113.7		962.6		1,181.2
Other	39.6		34.3		39.0
Total Operating Revenues	4,462.0		4,190.8		4,431.5
Operating Expenses
Fuel and Purchased Power	1,158.1		1,103.8		1,174.5
Cost of Gas Sold	674.1		545.8		728.7
Other Operation and Maintenance	1,522.0		1,476.5		1,613.4
Depreciation and Amortization	320.2		296.4		257.0
Property and Revenue Taxes	116.2		120.6		113.1
Total Operating Expenses	3,790.6		3,543.1		3,886.7
Treasury Grant	48.0		—		—
Operating Income	$	719.4	$	647.7	$	544.8

43 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

2013 vs. 2012:   Our utility energy segment contributed $719.4 million of operating income during 2013 compared with $647.7 million of operating income during 2012. The increase in operating income was primarily caused by favorable winter weather during 2013 and pricing increases, partially offset by an increase in operation and maintenance expense and depreciation.

2012 vs. 2011:   Our utility energy segment contributed $647.7 million of operating income during 2012 compared with $544.8 million of operating income during 2011. The increase in operating income was primarily caused by decreased other operation and maintenance expense and decreased fuel and purchased power expenses.

Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2013 with similar information for 2012 and 2011, including a summary of electric operating revenues and electric sales by customer class:

	Electric Revenues and Gross Margin						MWh Sales
Electric Utility Operations	2013		2012		2011		2013	2012	2011
	(Millions of Dollars)						(Thousands)
Customer Class
Residential	$	1,208.6	$	1,163.9	$	1,159.2	8,141.9	8,317.7	8,278.5
Small Commercial/Industrial	1,048.0		1,013.6		1,006.9		8,860.4	8,860.0	8,795.8
Large Commercial/Industrial	711.9		744.3		763.7		8,673.4	9,710.7	9,992.2
Other - Retail	23.4		22.8		22.9		152.3	154.8	153.6
Total Retail	2,991.9		2,944.6		2,952.7		25,828.0	27,043.2	27,220.1
Wholesale - Other	143.7		144.4		154.0		1,953.5	1,566.6	2,024.8
Resale - Utilities	143.2		53.4		69.5		4,382.7	1,642.4	2,065.7
Other Operating Revenues	28.4		51.5		35.1		—	—	—
Total	3,307.2		3,193.9		3,211.3		32,164.2	30,252.2	31,310.6
Electric Customer Choice (a)	1.5		—		—		813.0	—	—
Total, including electric customer choice	3,308.7		3,193.9		3,211.3
Fuel and Purchased Power
Fuel	611.1		541.6		644.4
Purchased Power	533.4		548.7		514.8
Total Fuel and Purchased Power	1,144.5		1,090.3		1,159.2
Total Electric Gross Margin	$	2,164.2	$	2,103.6	$	2,052.1
Weather - Degree Days (b)
Heating (6,580 Normal)							7,233	5,704	6,633
Cooling (730 Normal)							688	1,041	793

(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

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 is primarily related to our 2013 Wisconsin Rate Case. For information on the Treasury Grant and the rate order in the 2013 rate case, see

44 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments and -- Utility Rates and Regulatory Matters, respectively.

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

• A $23.1 million decrease in other operating revenues, primarily driven by the amortization of $25.9 million in 2012 related to the settlement with the United States Department of Energy (DOE). For additional information on the DOE settlement, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters -- 2012 Fuel Cost Plan Request.

• A return to more normal summer weather as compared to the prior year 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 a decrease in sales to the two iron ore mines in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased 3.0%. The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers have switched to an alternative electric supplier. 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.

2012 vs. 2011:   Our electric utility operating revenues decreased by $17.4 million, or 0.5%, when compared to 2011. The most significant factors that caused a change in revenues were:

• Favorable weather as compared to 2011 that increased electric revenues by an estimated $28.5 million.

• Other operating revenues increased by approximately $16.4 million, driven by the $25.9 million amortization of the settlement with the DOE.

• A planned outage at an iron ore mine in 2012 and the conversion to self-generation of two other large customers decreased electric revenues by an estimated $20.4 million.

• A $16.2 million reduction in sales for resale due to reduced sales into the MISO Energy Markets.

• Lower MWh sales to our wholesale customers, which decreased revenue by an estimated $12.4 million as compared to 2011.

As measured by cooling degree days, 2012 was 49.6% warmer than normal, and 31.3% warmer than 2011. We believe the warmer summer weather was the primary reason for the 0.5% increase in residential sales and the 0.7% increase in small commercial/industrial sales. The increase due to warmer summer weather was partially offset by reduced sales from warmer winter weather in the first quarter of 2012 as compared to the first quarter of 2011.

Sales to our large commercial/industrial customers decreased by 2.8% primarily due to the planned outage at one of the iron ore mines in Michigan and the conversion to self-generation of two other large customers. Excluding sales to these three customers, MWh sales to large commercial/industrial customers increased by 1.1%. Wholesale sales decreased primarily due to the low market price of power in 2012 as compared to 2011, which caused some of these customers to obtain energy from the MISO market rather than through our contracts. The reduction did not impact the majority of revenue received from these customers, which is tied to demand. The lower market price of power also reduced our ability to sell energy into the MISO Energy Markets.

Electric Fuel and Purchased Power Expenses

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.

45 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

2012 vs. 2011:   Our electric fuel and purchased power costs decreased by $68.9 million, or approximately 5.9%, when compared to 2011. This decrease was primarily caused by a 3.4% decrease in total MWh sales as well as a reduction in our average cost of fuel and purchased power because of lower natural gas prices.

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 2013, 2012 and 2011.

Gas Utility Operations	2013		2012		2011
	(Millions of Dollars)
Operating Revenues	$	1,113.7	$	962.6	$	1,181.2
Cost of Gas Sold	674.1		545.8		728.7
Gross Margin	$	439.6	$	416.8	$	452.5

We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under GCRMs. The following table compares our gas utility gross margin and therm deliveries by customer class during 2013, 2012 and 2011:

	Gross Margin						Therm Deliveries
Gas Utility Operations	2013		2012		2011		2013	2012	2011
	(Millions of Dollars)						(Millions)
Customer Class
Residential	$	284.2	$	267.9	$	290.2	872.0	676.4	776.8
Commercial/Industrial	96.5		88.8		101.5		499.9	390.6	461.7
Interruptible	1.8		1.7		1.8		18.1	14.6	16.0
Total Retail	382.5		358.4		393.5		1,390.0	1,081.6	1,254.5
Transported Gas	51.7		52.9		52.6		1,052.8	1,140.4	899.6
Other Operating	5.4		5.5		6.4		—	—	—
Total	$	439.6	$	416.8	$	452.5	2,442.8	2,222.0	2,154.1
Weather - Degree Days (a)
Heating (6,580 Normal)							7,233	5,704	6,633

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

2013 vs. 2012:   Our total retail gas margin increased by $24.1 million, or approximately 6.7%, when compared to 2012. We estimate that colder winter weather increased gas margins by approximately $56.9 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 $42.3 million because of lower gas rates that became effective January 1, 2013.

2012 vs. 2011:   Our total retail gas margin decreased by $35.1 million, or approximately 8.9%, when compared to 2011 primarily because of a decrease in sales volumes as a result of warmer winter weather. As measured by heating degree days, 2012 was 14.0% warmer than 2011 and 14.4% warmer than normal.

Transported gas volumes increased by 26.8% when compared to 2011. Virtually all of the volume increase related to gas used in electric generation, which has a small impact on margin.

46 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

Other Operation and Maintenance Expense

2013 vs. 2012:   Our other operation and maintenance expense increased by $45.5 million, or approximately 3.1%, when compared to 2012. This increase was primarily driven by the reinstatement of $148.0 million of regulatory amortizations, offset in part by a $50.1 million reduction in bad debt expense related to our natural gas customers and continued cost control efforts across our utilities. For additional information on the regulatory amortizations, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters -- 2012 Wisconsin Rate Case.

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

2012 vs. 2011:   Our other operation and maintenance expense decreased by $136.9 million, or approximately 8.5%, when compared to 2011. This decrease is primarily due to the one year suspension of $148.0 million of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case.

Depreciation and Amortization Expense

2013 vs. 2012:   Depreciation and Amortization expense increased by $23.8 million, or approximately 8.0%, when compared to 2012. This increase was primarily because of an overall increase in utility plant in service. 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. In addition, our new biomass plant went into service in November 2013. For additional information on the AQCS and biomass facility, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters -- Oak Creek Air Quality Control System and -- Renewables, Efficiency, and Conservation, respectively.

We expect depreciation and amortization expense to increase in 2014 primarily as a result of an increase in utility plant in service related to the biomass plant, which will have been in service a full year.

2012 vs. 2011:   Depreciation and Amortization expense increased by $39.4 million, or approximately 15.3%, when compared to 2011. This increase was primarily because of an overall increase in utility plant in service. The Glacier Hills Wind Park went into service in December 2011. In addition, the emission control equipment for units 5 and 6 of the Oak Creek AQCS project went into service in March 2012, and for units 7 and 8 in September 2012.

Treasury Grant

During 2013, we recognized $48 million of income related to a Treasury Grant associated with our recently completed biomass plant. The grant income that we recognized in income is equal to the bill credits provided to our retail electric customers in Wisconsin before related tax benefits. For additional information on the Treasury Grant, see Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments.

During 2014, we expect to recognize approximately $13 million of grant income. This amount is equal to the bill credits we expect to provide to our retail electric customers in Wisconsin before related tax benefits.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our non-utility energy segment consists primarily of our PTF units (PWGS 1, PWGS 2, OC 1 and OC 2).

This segment reflects the lease revenues on the new units as well as the depreciation expense. Operating and maintenance costs and limited management fees associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.

47 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

	2013		2012		2011
	(Millions of Dollars)
Operating Revenues	$	446.7	$	439.9	$	435.1
Operation and Maintenance Expense	12.5		14.0		13.7
Depreciation Expense	67.1		67.1		72.5
Operating Income	$	367.1	$	358.8	$	348.9

2013 vs. 2012:   Non-utility energy segment operating income increased $8.3 million, or approximately 2.3%, when compared to 2012. The increase primarily relates to the increase in operating revenues related to the final approved construction costs for the Oak Creek expansion as part of the 2013 Wisconsin Rate Case.

In 2014, we expect our non-utility energy segment operating revenue to stay relatively flat compared to 2013.

2012 vs. 2011:    Non-utility energy segment operating income increased $9.9 million, or approximately 2.8%, when compared to 2011. This increase primarily relates to a decrease in depreciation expense related to finalized depreciable lives of the Oak Creek expansion units and a full year's earnings in 2012 for OC 2 compared to eleven and a half months of earnings for 2011.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

2013 vs. 2012:   Corporate and other affiliates had an operating loss of $6.4 million in 2013 compared with an operating loss of $6.2 million in 2012.

2012 vs. 2011:   Corporate and other affiliates had an operating loss of $6.2 million in 2012 compared with an operating loss of $6.4 million in 2011.

CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET

Other Income and Deductions, net	2013		2012			2011
	(Millions of Dollars)
AFUDC - Equity	$	18.3	$	35.3		$	59.4
Other, net	0.5		(0.5		)	3.3
Total Other Income and Deductions, net	$	18.8	$	34.8		$	62.7

2013 vs. 2012:   Other income and deductions, net decreased by approximately $16.0 million, or 46.0%, 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.

During 2014, we expect to see a reduction in AFUDC - Equity as we expect to have fewer large construction projects.

2012 vs. 2011:   Other income and deductions, net decreased by approximately $27.9 million, or 44.5%, when compared to 2011. This decrease primarily relates to lower AFUDC - Equity related to the Glacier Hills Wind Park, which went into service in December 2011, as well as 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.

48 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

CONSOLIDATED INTEREST EXPENSE, NET

Interest Expense, net	2013		2012		2011
	(Millions of Dollars)
Gross Interest Costs	$	261.5	$	264.1	$	262.5
Less: Capitalized Interest	9.4		15.9		26.7
Interest Expense, net	$	252.1	$	248.2	$	235.8

2013 vs. 2012:   Our net interest expense increased by $3.9 million, or 1.6%, as compared to 2012 primarily because of lower capitalized interest. Our capitalized interest decreased by $6.5 million primarily because of lower construction work in progress.

During 2014, we expect to see slightly lower net interest expense as gross interest costs are expected to decrease due to a lower weighted average embedded interest rate on our long-term debt. We expect this decrease will be partially offset by a reduction in capitalized interest as a result of the biomass plant going into service in 2013.

2012 vs. 2011:   Our net interest expense increased by $12.4 million, or 5.3%, as compared to 2011 primarily because of lower capitalized interest. Our capitalized interest decreased by $10.8 million primarily because we stopped capitalizing interest on the Oak Creek AQCS project when the emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8, and the Glacier Hills Wind Park which went into service in December 2011.

CONSOLIDATED INCOME TAX EXPENSE

2013 vs. 2012:   Our effective tax rate applicable to continuing operations was 36.9% in 2013 compared to 35.9% in 2012. This increase in our effective tax rate was due to reduced domestic production activities deductions and AFUDC - Equity. For further information, see Note G -- Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2014 annual effective tax rate to be between 37.5% and 38.5%.

2012 vs. 2011:   Our effective tax rate applicable to continuing operations was 35.9% in 2012 compared to 34.0% in 2011. This increase in our effective tax rate was primarily the result of decreased AFUDC - Equity.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2013, 2012 and 2011:

	2013			2012			2011
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	1,231.0		$	1,173.9		$	993.4
Investing Activities	$	(745.8	)	$	(729.6	)	$	(892.5	)
Financing Activities	$	(494.8	)	$	(422.8	)	$	(111.3	)

Operating Activities

2013 vs. 2012:   Cash provided by operating activities was $1,231.0 million during 2013, which was an increase of $57.1 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 $100 million during 2012. In addition, we had higher net income, depreciation expense and amortization expense. Included in the higher amortization expense is a $77.9 million increase in the

49 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

amortization of regulatory items. Partially offsetting these items is an increase in accounts receivable and accrued revenues of $201.2 million because of colder winter weather and the Treasury Grant.

2012 vs. 2011:   Cash provided by operating activities was $1,173.9 million during 2012, which was an increase of $180.5 million over 2011. The largest increases in cash provided by operating activities related to higher net income, higher depreciation expense, and lower contributions to our benefit plans. Combined these items increased operating cash flows by $232.8 million as compared to 2011. Partially offsetting these items, our non-cash charges related to the amortization of certain regulatory assets and liabilities was $148.0 million lower during 2012 as compared to 2011 because the PSCW allowed us to suspend these amortizations in 2012.

Investing Activities

2013 vs. 2012:   Cash used in investing activities was $745.8 million during 2013, which was $16.2 million higher than 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 DOE settlement. Our capital expenditures decreased by $19.6 million during 2013 as compared to 2012, primarily because of decreased spending as the Oak Creek AQCS project went into service in 2012.

The following table identifies capital expenditures by year:

Capital Expenditures	2013		2012		2011
	(Millions of Dollars)
Utility	$	657.9	$	697.3	$	792.2
We Power	26.1		5.5		31.2
Other	3.4		4.2		7.4
Total Capital Expenditures	$	687.4	$	707.0	$	830.8

2012 vs. 2011:   Cash used in investing activities was $729.6 million during 2012, which was $162.9 million lower than 2011. This decrease was primarily caused by a decrease in capital expenditures and a decrease in our restricted cash. Our capital expenditures decreased by $123.8 million in 2012 compared to 2011, primarily because of decreased spending on the Oak Creek AQCS project which went into service in March and September of 2012. In 2011, we received $45.5 million in proceeds from the settlement with the DOE. The proceeds were treated as restricted cash, which was recorded as cash used in investing activities. In 2012, we released $42.8 million of the proceeds through bill credits and the reimbursement of costs. The decrease was offset by a reduction in proceeds from asset sales. In 2011, we received proceeds from asset sales totaling $41.5 million, which primarily relates to the sale of our interest in Edgewater Generating Unit 5, as compared to proceeds of $8.7 million in 2012.

Financing Activities

The following table summarizes our cash flows from financing activities:

	2013			2012			2011
	(Millions of Dollars)
Dividends on Common Stock	$	(328.9	)	$	(276.3	)	$	(242.0	)
Common Stock Repurchased, Net	(174.9		)	(103.4		)	(139.5		)
Net Increase (Decrease) in Debt	(3.4		)	(43.8		)	265.4
Other	12.4			0.7			4.8
Cash Used in Financing	$	(494.8	)	$	(422.8	)	$	(111.3	)

2013 vs. 2012:   Cash used in financing activities was $494.8 million during 2013, compared to $422.8 million during 2012. Our dividends paid on common stock increased by $52.6 million during 2013 as compared to 2012, as a result of increases in the quarterly common stock dividend of 13.3% and 12.5% in the first and third quarter, respectively.

50 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

In addition, on May 5, 2011, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock through the end of 2013. In 2013, we repurchased approximately 3.0 million shares in the open market pursuant to this program at a total cost of $126.0 million, compared to 1.5 million shares at a cost of $51.8 million in 2012.

2012 vs. 2011:   Cash used in financing activities was $422.8 million during 2012, compared to $111.3 million during 2011. In 2012, we issued $251.8 million in long term debt, including $250.0 million by Wisconsin Electric, and used the proceeds to repay short-term debt and for other general corporate purposes. In 2011, we issued $720.0 million of long-term debt. In addition, we retired $466.6 million of long-term debt in 2011. Short-term debt decreased $275.3 million in 2012 compared to a $12.0 million increase in 2011. In addition, our common stock dividends increased in 2012 as we raised our quarterly dividend rate by 15.4%.

No new shares of Wisconsin Energy's common stock were issued in 2013, 2012 or 2011. During these years, our independent plan agents purchased, in the open market, 2.4 million shares at a cost of $97.4 million, 2.8 million shares at a cost of $101.4 million and 3.0 million shares at a cost of $93.9 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2013, 2012 and 2011, we received proceeds of $48.5 million, $49.8 million and $54.4 million, respectively, related to the exercise of stock options. In addition, we instructed our independent agents to purchase shares of our common stock in the open market to satisfy our obligations under our stock purchase and dividend reinvestment plan and various employee benefit plans.

CAPITAL RESOURCES AND REQUIREMENTS

Liquidity

We anticipate meeting our capital requirements during 2014 and beyond primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors.

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 arrangements, access to capital markets and internally generated cash.

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.

As of December 31, 2013, we had approximately $1.2 billion of available, undrawn lines under our bank back-up credit facilities. As of December 31, 2013, we had approximately $537.4 million of commercial paper outstanding on a consolidated basis that was supported by the available lines of credit. During 2013, our maximum commercial paper outstanding was $594.5 million with a weighted-average interest rate of 0.25%. For additional information regarding our commercial paper balances during 2013, 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 facilities as of December 31, 2013:

Company	Total Facility		Letters of Credit		Credit Available		Facility Expiration
	(Millions of Dollars)
Wisconsin Energy	$	400.0	$	0.1	$	399.9	December 2017
Wisconsin Electric	$	500.0	$	6.1	$	493.9	December 2017
Wisconsin Gas	$	350.0	$	—	$	350.0	December 2017

51 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

Each of these facilities has a renewal provision for two one-year extensions, subject to lender approval.

The following table shows our capitalization structure as of December 31, 2013 and 2012, as well as an adjusted capitalization structure that we believe is consistent with the manner in which the rating agencies currently view Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067 (Junior Notes):

	2013						2012
Capitalization Structure	Actual			Adjusted			Actual			Adjusted
	(Millions of Dollars)
Common Equity	$	4,233.0		$	4,483.0		$	4,135.1		$	4,385.1
Preferred Stock of Subsidiary	30.4			30.4			30.4			30.4
Long-Term Debt (including current maturities)	4,705.4			4,455.4			4,865.9			4,615.9
Short-Term Debt	537.4			537.4			394.6			394.6
Total Capitalization	$	9,506.2		$	9,506.2		$	9,426.0		$	9,426.0
Total Debt	$	5,242.8		$	4,992.8		$	5,260.5		$	5,010.5
Ratio of Debt to Total Capitalization	55.2		%	52.5		%	55.8		%	53.2		%

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.

Included in Long-Term Debt on our Consolidated Balance Sheets as of December 31, 2013 and 2012 is $500 million aggregate principal amount of the Junior Notes. The adjusted presentation attributes $250 million of the Junior Notes to Common Equity and $250 million to Long-Term Debt. We believe this presentation is consistent with the 50% or greater equity credit the majority of rating agencies currently attribute to the Junior Notes.

The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages Wisconsin Energy's capitalization structure, including its total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

As described in Note H -- Common Equity, in the Notes to Consolidated Financial Statements, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.

Wisconsin Electric is the obligor under two series of tax exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric issued commercial paper to fund the purchase of the bonds. As of December 31, 2013, the repurchased bonds were still outstanding, but were not reported as long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

On December 5, 2013, the Board of Directors reviewed management's plan to maintain an appropriate capital structure by retiring up to $500 million of the holding company's obligations during the period 2014 through 2017.

Bonus Depreciation Provisions

The American Taxpayer Relief Act of 2012 was signed into law on January 2, 2013, which extended the 50% bonus depreciation rules to include assets placed in service in 2013. These rules apply to the biomass plant we constructed in Rothschild, which went into service in November 2013. As a result of the increased federal tax

52 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

depreciation for 2013 and prior years, we did not make federal income tax payments for 2013 and do not anticipate making federal income tax payments for 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, 2013, we estimate that the collateral or the termination payments required under these agreements totaled approximately $214.6 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 January 2014, Moody's raised the ratings of Wisconsin Energy (senior unsecured to A2 from A3; junior subordinated to A3 from Baa1; commercial paper to P-1 from P-2), Wisconsin Electric (senior unsecured to A1 from A2), Wisconsin Gas (senior unsecured to A1 from A2), Elm Road Generating Station Supercritical, LLC (ERGSS) (senior notes to A1 from A2) and Wisconsin Energy Capital Corporation (WECC) (senior unsecured to A2 from A3). The commercial paper ratings of Wisconsin Electric and Wisconsin Gas remained at P-1. Moody's assigned a stable ratings outlook to each company.

In December 2013, S&P raised the ratings of Wisconsin Gas commercial paper to A-1 from A-2, and senior unsecured to A from A-. S&P also affirmed the stable rating outlook.

In June 2013, S&P affirmed the ratings of Wisconsin Energy (commercial paper, A-2; senior unsecured, BBB+; junior subordinated, BBB), Wisconsin Electric (commercial paper, A-2; senior unsecured, A-), Wisconsin Gas (commercial paper, A-2; senior unsecured, A-), WECC (senior unsecured, A-) and ERGSS (senior notes, A-). S&P also revised the ratings outlooks assigned to each company from positive to stable.

In June 2013, Fitch Ratings (Fitch) affirmed the ratings of Wisconsin Energy (commercial paper, F2; senior unsecured, A-; junior subordinated, BBB), Wisconsin Electric (commercial paper, F1; senior unsecured, A+), Wisconsin Gas (commercial paper, F1), WECC (senior unsecured, A-) and ERGSS (senior notes, A+). At the same time, Fitch lowered the senior unsecured rating of Wisconsin Gas to A from A+. Fitch also affirmed the stable ratings outlooks assigned to each company.

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:

Capital Expenditures	2014		2015		2016
	(Millions of Dollars)
Utility	$	667.9	$	777.6	$	587.6
We Power	38.6		19.8		28.7
Other	4.5		6.8		5.5
Total	$	711.0	$	804.2	$	621.8

53 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

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 our utility energy segment.

Common Stock Matters:   On December 5, 2013, our Board of Directors authorized a new share repurchase program for up to $300 million of our common stock from January 1, 2014 through the end of 2017.  Funds for the repurchases are expected to come from internally generated funds and working capital supplemented, if required in the short-term, by the sale of commercial paper.  The repurchase program does not obligate Wisconsin Energy to acquire any specific number of shares and may be suspended or terminated by the Board of Directors at any time.

In addition, on January 16, 2014, our Board of Directors increased our quarterly common stock dividend to $0.39 per share, up approximately 2.0%, from $0.3825 per share.

Investments in Outside Trusts:   We use outside trusts to fund our pension and certain other post-retirement obligations. These trusts had investments of approximately $1.8 billion as of December 31, 2013. These trusts hold investments that are subject to the volatility of the stock market and interest rates.

During 2013, we made no contributions to our qualified pension plans or our qualified Other Post-Retirement Employee Benefit (OPEB) plans. During 2012, we contributed $95.6 million to our qualified pension plans and $4.4 million to our qualified OPEB plans. Future contributions to the plans will be dependent upon many factors, including the performance of existing 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.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

Contractual Obligations/Commercial Commitments:   We have the following contractual obligations and other commercial commitments as of December 31, 2013:

	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)	$	8,709.7	$	556.3	$	917.8	$	674.8	$	6,560.8
Capital Lease Obligations (c)	215.9		41.9		88.6		28.6		56.8
Operating Lease Obligations (d)	40.5		3.9		7.6		6.3		22.7
Purchase Obligations (e)	12,189.3		892.3		1,309.4		1,067.9		8,919.7
Other Long-Term Liabilities	1,000.1		104.1		199.4		201.0		495.6
Total Contractual Obligations	$	22,155.5	$	1,598.5	$	2,522.8	$	1,978.6	$	16,055.6

(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 of Wisconsin Electric for power purchase commitments. This amount does not include We Power leases to Wisconsin Electric which are eliminated upon consolidation.

(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 related to utility operations and for construction, information technology and other services for utility and We Power 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.

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:   Our utility energy segment accounts for its 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 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

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

liabilities. As of December 31, 2013, our regulatory assets totaled $1,108.5 million and our regulatory liabilities totaled $879.1 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 Wisconsin Electric's 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 Utility 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 2012 rate order, the PSCW authorized continued use of the escrow method of accounting for bad debt costs through December 31, 2014. 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 GCRMs, our gas utility operations receive 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 the natural gas utilities' GCRMs, see Utility Rates and Regulatory Matters.

Weather:   Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Wisconsin Electric's 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 the utility segment's service territory during 2013, 2012 and 2011, 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, 2013. 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, 2013 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2013, we had $537.4 million of commercial paper outstanding with a weighted average interest rate of 0.20% and $147.0 million of variable-rate long-term debt outstanding with a weighted average interest rate of 0.50%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $6.8 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 assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

The fair value of our trust fund assets as of December 31, 2013 was approximately:

	Millions of Dollars
Pension trust funds	$	1,451.0
Other post-retirement benefits trust funds	$	327.6

The expected long-term rate of return on plan assets for 2014 is 7.25% and 7.5%, respectively, for the pension and OPEB plans.

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.

We consult with our investment advisors on an annual basis to help us 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.

Inflation:   We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance and new generation 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 PWGS1, PWGS2, OC1 and OC2.

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

We are recovering our costs in these units through lease payments associated with PWGS1, PWGS2, OC1 and OC 2 that are billed from We Power to Wisconsin Electric and then recovered in Wisconsin Electric's rates as authorized by the PSCW, the MPSC and FERC. Under the lease terms, our return is calculated using a 12.7% return on equity and the equity ratio is assumed to be 53% for the PWGS Units and 55% for the Oak Creek Units.

Wisconsin Electric operates PWGS1, PWGS2, OC1 and OC2 and is authorized by the PSCW to fully recover prudently incurred operating and maintenance costs in its Wisconsin electric rates. As the operator of the units, Wisconsin Electric 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 capital improvements or further investments to be added to the lease payments, and ultimately to be recovered in Wisconsin Electric's rates.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

We Power assigned its warranty rights to Wisconsin Electric 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. Bechtel and Wisconsin Electric continue to work through two remaining items.

Pursuant to the terms of this settlement agreement, Bechtel achieved final acceptance of both Oak Creek expansion units.

UTILITY 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. Within our regulated segment, for the year ended December 31, 2013, we estimate that approximately 87% of our electric revenues were regulated by the PSCW, 4% were regulated by the MPSC and the balance of our electric revenues was regulated by FERC. Because of the loss of several Michigan customers to an alternative electric supplier, the percentage of revenues regulated by the MPSC is likely to decline in the future. 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

2013 Wisconsin Rate Case:In March 2012, Wisconsin Electric and Wisconsin Gas 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 Wisconsin Electric's Wisconsin retail electric customers of approximately $70 million (2.6%) for 2013. This amount reflects an offset of approximately $63 million (2.3%) of bill credits related to the proceeds of the Treasury Grant, including related tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133 million (4.8%) for 2013.

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

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

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

• A rate decrease of approximately $34 million (5.5%) for Wisconsin Gas' natural gas customers for 2013, with no rate adjustment in 2014. The new Wisconsin Gas rates reflect a $43.8 million reduction in bad debt expense.

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

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

These rate adjustments were effective January 1, 2013. In addition, the PSCW indicated that Wisconsin Electric's and Wisconsin Gas' allowed return on equity would remain at 10.4% and 10.5%, respectively. The PSCW also approved escrow accounting treatment for the Treasury Grant. In the first half of 2014, Wisconsin Electric and Wisconsin Gas expect to seek base rate increases to be effective in 2015.

2012 Wisconsin Rate Case:   In May 2011, Wisconsin Electric and Wisconsin Gas 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, Wisconsin Electric and Wisconsin Gas requested that the PSCW issue an order that, among other things:

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

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

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

• Authorizes the refund of $26 million of net proceeds from Wisconsin Electric's settlement of the spent nuclear fuel litigation with the DOE.

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

2012 Michigan Rate Case:In July 2011, Wisconsin Electric 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 Wisconsin Electric's 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 2014, Wisconsin Electric expects to seek a base rate increase to be effective in 2015.

2010 Wisconsin Rate Case:   In March 2009, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. In December 2009, the PSCW approved the following rate adjustments:

• An increase of approximately $85.8 million (3.35%) in retail electric rates for Wisconsin Electric;

• A decrease of approximately $2.0 million (0.35%) for natural gas service for Wisconsin Electric;

• An increase of approximately $5.7 million (0.70%) for natural gas service for Wisconsin Gas; and

• A decrease of approximately $0.4 million (1.65%) for Wisconsin Electric's Valley steam utility customers and a decrease of approximately $0.1 million (0.47%) for its Milwaukee County steam utility customers.

These rate adjustments became effective January 1, 2010. In addition, the PSCW lowered the authorized return on equity for Wisconsin Electric from 10.75% to 10.4% and for Wisconsin Gas from 10.75% to 10.5%.

As part of its final decision in the 2010 rate case, the PSCW authorized Wisconsin Electric to reopen the docket in 2010 to review updated 2011 fuel costs. In September 2010, Wisconsin Electric filed an application with the PSCW to reopen the docket to review updated 2011 fuel costs and to set rates for 2011 that reflect those costs. The PSCW issued a final decision, increasing annual Wisconsin retail rates by $25.4 million effective April 29, 2011. The net increase was driven primarily by an increase in the delivered cost of coal.

2010 Michigan Rate Increase Request:   In July 2009, Wisconsin Electric 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, effective November 1, 2010. In November 2010, the mines filed a Claim of Appeal of the October 2010 order with the Michigan Court of Appeals. In December 2010, the MPSC filed a Motion for Remand with the Court of Appeals. In March 2011, the Court of Appeals denied the Motion for Remand. All briefs have been filed and the case is awaiting scheduling of oral argument.

Wisconsin Fuel Proceedings

Embedded within Wisconsin Electric's base 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.

2014 Fuel Cost Plan Request:On July 30, 2013, Wisconsin Electric filed its 2014 fuel cost plan with the PSCW requesting authority to decrease Wisconsin retail electric customers rates approximately $36 million in the form of a fuel credit primarily related to a reduction in delivered coal costs. The plan was approved by the PSCW on December 20, 2013.

2012 Fuel Cost Plan Request:In August 2011, Wisconsin Electric filed a $50 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The primary reasons for the increase

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

were projected higher coal, coal transportation and purchased power costs. In January 2012, the PSCW issued an order which provided for an increase in fuel costs of approximately $26 million, offset by approximately $26 million from the settlement with the DOE.

In November 2000, Wisconsin Electric filed a complaint against the DOE in the Court of Federal Claims for DOE's failure to remove used nuclear fuel from Point Beach, which Wisconsin Electric owned until September 2007. We negotiated a settlement with the DOE for $45.5 million, which we received in the first quarter of 2011. This amount, net of costs incurred, was returned to customers.

Other Utility Rate Matters

Oak Creek Air Quality Control System:   In July 2008, we received approval from the PSCW granting Wisconsin Electric authority to construct wet flue gas desulfurization and selective catalytic reduction facilities at Oak Creek Power Plant units 5-8. Construction of these emission controls began in late July 2008. In March 2012, the wet flue gas desulfurization and selective catalytic reduction equipment for units 5 and 6 was placed into commercial operation. In September 2012, the equipment for units 7 and 8 was placed into commercial operation. The final cost of completing this project was approximately $740 million ($900 million including AFUDC).

Electric Transmission Cost Recovery:   Wisconsin Electric divested its transmission assets with the formation of ATC in January 2001. We now procure transmission service from ATC at FERC approved tariff rates. In connection with the formation of ATC, our transmission costs have escalated due to the socialization of costs within ATC 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 we deferred at our weighted-average cost of capital. As of December 31, 2013, we had $126.8 million of unrecovered transmission costs related to prior deferrals that are not subject to escrow accounting because our 2008 and 2010 PSCW rate orders provided for recovery of these costs. In the 2013 Wisconsin Rate Case, the PSCW reauthorized escrow accounting for future transmission costs and we are allowed to accrue these costs on a net of tax basis at the short-term debt rate.

Gas Cost Recovery Mechanism:   Our natural gas operations operate under GCRMs as approved by the PSCW. Generally, the GCRMs allow for a dollar for dollar recovery of gas costs. The GCRMs use 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. Wisconsin Electric's baseline renewable energy percentage is 2.27%. Under Act 141, Wisconsin Electric could not decrease its renewable energy percentage for the years 2006-2009, and for the years 2010-2014, it must increase its renewable energy percentage at least two percentage points to a level of 4.27%. As of December 31, 2013, 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, Wisconsin Electric has 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 on November 8, 2013. Wood waste and wood shavings are used to produce renewable electricity and will also support Domtar's sustainable papermaking operations. The final cost of completing this project was $269.0 million, excluding AFUDC. 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.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

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 2013. The funding required by Act 141 for 2014 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. 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.

Western Gas Lateral:   We are projecting the need for additional capacity for our natural gas distribution network in the western part of Wisconsin to address reliability and meet customer demand. We filed an application with the PSCW seeking approval to construct a new natural gas lateral on March 28, 2013. The anticipated cost of the initial phase of this project is approximately $150 million to $170 million, excluding AFUDC.

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 2013 and 2012. 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 2014. 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 our utility and non-utility energy segments include but are not limited to current and future regulation of: (1) air emissions such as SO₂, NO_x, fine particulates, mercury and greenhouse gas emissions; (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, Wisconsin Electric reached a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired generating facilities. In July 2003, the Consent

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

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 order to achieve the reductions agreed to in the Consent Decree, over the past 10 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.

National Ambient Air Quality Standards (NAAQS)

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

In January2010, the EPA announced its decision to further lower the 2008 8-hour ozone standard. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard. In January 2014, environmental groups petitioned the U.S. District Court for the Northern District of California to order the EPA to propose a new ozone standard by the end of 2014 and to finalize the standard by October 2015. We expect that the EPA could lower the current 8-hour ozone standard from its current level.

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 SIP including reasonably available control technology (RACT) regulations. In December 2012, the EPA re-proposed this determination along with further clarification of its authority to suspend RACT and other SIP requirements. Until the EPA finalizes this action and redesignates the three counties to attainment, our generating facilities in the non-attainment counties will continue to be subject to more stringent construction permitting requirements and emission offset provisions. Also in December 2012, the EPA issued a revised and more stringent annual PM_2.5 standard. Current monitored air quality data indicates that all areas of Wisconsin and Michigan's Upper Peninsula meet the revised standard. Although we do not expect the lower standard to impose any additional requirements on our operations, until the EPA develops a rule or guidance that dictates implementation of the new standard, we are unable to predict how these actions may affect any future construction permitting activities.

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

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

If the new standard remains in place, we do not believe that we will need to make any significant additional expenditures at the majority of our generating units because of prior investments in pollution control equipment. However, if the new standard does remain in place we believe that additional environmental controls will be required at PIPP located in the Upper Peninsula of Michigan.

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In November of 2012, we entered into a joint venture agreement with Wolverine whereby Wolverine would pay for the installation of the air quality control systems at PIPP and receive a minority undivided ownership interest in the plant in return. However, in light of the loss of retail electric customers in Michigan due to that state’s alternative electric supplier program (see Restructuring in Michigan under Industry Restructuring and Competition), we re-evaluated options related to the ownership and operation of PIPP including different alternatives for the joint venture with Wolverine. Ultimately, in December 2013, Wisconsin Electric and Wolverine decided to terminate the joint venture. We are currently evaluating options for the long-term future of PIPP, including the potential sale of the plant. At the same time, we are analyzing several environmental compliance options at PIPP.

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

Nitrogen Dioxide Standard:In January 2010, the EPA announced a new hourly Nitrogen Dioxide standard, which became effective in April 2010. We are unable to predict the impact on the operation of our generation facilities until final attainment designations are made and until any potential additional rules are adopted.

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 currently evaluating several available options for PIPP to comply with MATS. In April 2013, we received a one year MATS compliance extension through April 16, 2016 from the MDEQ.

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 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 boilers at the Milwaukee County Power Plant (MCPP) are subject to this rule. We are currently evaluating compliance options for the three coal fired boilers at MCPP.

Cross-State Air Pollution Rule:   In August 2011, the EPA issued the CSAPR, formerly known as the Clean Air Transport Rule. This rule was proposed in 2010 to replace the Clean Air Interstate Rule (CAIR), which had been remanded to the EPA in 2008. The stated purpose of the CSAPR is to limit the interstate transport of emissions of NO_x and SO₂ that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation plan. In February 2012, the EPA issued final technical revisions to the rule and issued a draft final rule which together delay the implementation date for certain penalty provisions that could potentially impact the PIPP and increase the number of allowances issued to the states of Michigan and Wisconsin. Even with technical revisions to the rule by the EPA, PIPP may not have been allocated sufficient allowances to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. This situation could then put the plant at risk for certain penalties under the rule.

The rule was scheduled to become effective January 1, 2012. However, we and a number of other parties sought judicial review of the rule, and in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CSAPR, keeping the CAIR in effect. The EPA successfully petitioned the United States Supreme Court, who heard the case in December 2013. A decision is expected by June 2014.

Wisconsin and Michigan Mercury Rules:   Both Wisconsin and Michigan have mercury rules that require a 90% reduction of mercury. We have plans in place to comply with those requirements and the costs of these plans are incorporated in our capital and operation and maintenance costs.

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.

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

Because of the court decision to vacate CSAPR and subsequent appeals, we will not be able to determine final regional haze requirements for NO_x and SO₂ at our facilities until the United States Supreme Court issues its decision and any subsequent rulemaking activities that may be required as a result of that decision have been finalized.

Climate Change:   We continue to take measures to reduce our emissions of greenhouse gases. We support flexible, market-based strategies to curb greenhouse gas emissions, including emissions trading, joint implementation 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 have taken, and continue to take, several steps to reduce our emissions of greenhouse gases, 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.

• Planning to convert the fuel source at the VAPP from coal to natural gas.

• Retired coal units 1-4 at PIPP.

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

The EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. On September 20, 2013, the EPA withdrew its 2012 proposed New Source Performance Standards greenhouse gas emissions rule, and issued new proposed rules with greenhouse gas limits for new fossil fueled power plants. The rule would not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines. Based upon currently available technology and the emission limits in the proposed rule, we believe that this rule, if promulgated, would effectively prohibit new conventional coal-fired power plants.

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

We are required to report our CO₂ equivalent emissions from our electric generating facilities to the EPA under its Mandatory Reporting of Greenhouse Gases rule. For 2012, we reported CO₂ equivalent emissions of approximately 18.1 million metric tonnes to the EPA, compared with approximately 22.4 million metric tonnes for 2011. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 21.9 million metric tonnes to the EPA for 2013. 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 amounts related to the natural gas our gas utility distributes and sells. For 2012, we reported approximately 8.4 million metric tonnes of CO₂ to the EPA related to our distribution and sale of natural gas, compared with approximately 9.5 million metric tonnes for 2011. Based upon our preliminary analysis of the

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monitoring data, we estimate that we will report CO₂ emissions of approximately 10.2 million metric tonnes to the EPA for 2013.

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, and anticipate that the conversion will be completed by the end of 2015 or early 2016. We filed for a Certificate of Authority from the PSCW on April 26, 2013, and received preliminary approval on January 30, 2014. We expect to receive a final written order by the end of the first quarter. The construction air permit for the gas conversion was issued by the WDNR on November 11, 2013.

In June 2012, we received approval from the PSCW to replace and upgrade the Lincoln Arthur natural gas main, which has the capability to accommodate the increased natural gas required for the conversion of VAPP to natural gas. Construction began on the Lincoln Arthur natural gas main in March 2013. 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. Final rules for cooling water intake systems at existing facilities (Phase II) were promulgated in 2004. However, as a result of litigation, the EPA withdrew the Phase II rule in July 2007 and advised states to use their best professional judgment in making BTA decisions while the rule remains suspended.

The EPA proposed a new Phase II rule in 2011; however, the promulgation of the final rule was delayed and is expected to occur by April 2014. Once the rule is final, we expect that it will apply to all of our existing generating facilities with cooling water intake structures other than the Oak Creek expansion, which was permitted under the Phase I rules.

The proposed rule would create an impingement mortality reduction standard for all existing facilities. One proposed approach would allow a facility owner to satisfy the BTA requirement with respect to impingement mortality reduction if it demonstrates that its cooling water intake system has a maximum intake velocity of no more than 0.5 feet per second. Oak Creek Power Plant Units 5-8, Pleasant Prairie and Port Washington Generating Station all employ technologies that have a cooling water intake withdrawal velocity of less than 0.5 feet per second. We are still evaluating impingement mortality reduction compliance options for the PIPP and VAPP.

The EPA has proposed that the BTA for entrainment mortality reduction be determined on a case-by-case basis. Therefore, permitting agencies would be required to determine BTA with respect to entrainment on a site-specific basis taking into consideration several factors. Because the entrainment reduction standard is a site-specific determination, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet this proposed requirement.

Depending on the final requirements of the Phase II rule, we may need to modify the cooling water intake systems at some of our facilities. However, we are not able to make a determination until after the Phase II rule is final.

In December, 2012, the WDNR issued a new Wisconsin Pollutant Discharge Elimination System (WPDES) permit for VAPP that became effective on January 1, 2013. The new permit includes significant new immediate and long-term permit 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 redesign of the cooling water intakes to minimize impingement impacts to aquatic organisms.

Steam Electric Effluent Guidelines:   These guidelines regulate waste water discharges from our power plant processes. In June 2013, the EPA issued a proposed rule for comment to modify these guidelines. We submitted comments primarily addressing potential effects to our wastewater treatment facilities and coal combustion residuals effluent management activities. The rules are expected to be finalized by May 2014. After promulgation of the final rules, the WDNR and MDEQ will need to modify state rules accordingly and then incorporate new

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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

Proposed 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. We anticipate that the EPA could take action on a final rule by the end of 2014. If coal combustion products are classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program.

If coal combustion products are classified as hazardous waste and we terminate our coal combustion products utilization program, we could be required to dispose of the coal combustion products at a significant cost to the Company, which could adversely impact our results of operations and financial condition.

In addition, the EPA finalized the Commercial and Industrial Solid Waste Incineration Units rule under the CAA, as well as the Non-Hazardous Secondary Materials Rule. We received a letter from the EPA in 2013 that allows us to continue ash recovery and reburn as a non-hazardous secondary material based on our processing of the materials prior to reburning as currently allowed under the Secondary Materials Rule.

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 aggressively 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 Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage and ground currents resulting from the operation of its 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.

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INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

The regulated energy industry continues to experience significant changes. FERC continues to support large RTOs, which affect the structure of the wholesale market. To this end, the MISO implemented bid-based markets, 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.

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

The mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers have switched to an alternative electric supplier. Sales to these customers, including the mines, totaled 2,173.6 GWh, or 7.6% of our retail electric sales for the year ended December 31, 2012. Previously, the owner of the mines announced that they would shut down the Empire mine by the end of 2014 or beginning of 2015.

We have taken, and will continue to take, multiple steps to mitigate these impacts in 2014 and going forward. 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. On January 30, 2014, we entered into a SSR Agreement with MISO to recover costs for operating and maintaining the units. The Agreement is effective February 1, 2014, has a one year term, and specifies monthly payments to Wisconsin Electric of $4.4 million to cover fixed costs. The Agreement also provides for the payment of our variable costs to operate and maintain the plant. MISO filed the SSR Agreement at FERC on January 31, 2014 and is requesting FERC's approval of this Agreement.

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

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

We do not expect the loss of these customers to have a material impact on our consolidated results of operations in 2014. Although the financial impact in future periods is uncertain, we expect that successful mitigation efforts and a reasonable regulatory response should make our net financial exposure immaterial.

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,

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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, 2013 through May 31, 2014. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

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 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 the changing 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

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

Paris Generating Station Units 1 and 4 Temporary Outage: Between 2000 and 2002, we replaced the blades on the four PSGS combustion turbine generators with blades that were approximately 7% more efficient. Although the work was performed as routine maintenance that we did not believe required a construction permit at the time and the plant has not been operated to use the potential additional capacity, the WDNR has indicated that it now considers this maintenance to be a modification requiring a construction permit. The WDNR issued a NOV to Wisconsin Electric on January 7, 2013 alleging violations of the new source review rules and certain Wisconsin environmental rules. At the same time, the WDNR also issued an administrative order that prohibits us from

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operating PSGS Units 1 and 4 until the earlier of: (1) Units 1 and 4 achieve the applicable NO_x emission rates; (2) the Wisconsin regulations are revised so that Units 1 and 4 can achieve the emission limits or are no longer subject to the limits; (3) the alleged modification is resolved through a consent decree; or (4) a court decides that the blade replacement project was not a major modification. We are presently evaluating alternative approaches to return these peaking units to service, and expect Units 1 and 4 to remain out of service until at least the end of the second quarter of 2014. In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR may revise the regulations applicable to Units 1 and 4 and allow those units to restart.

In February 2013, the Sierra Club filed for a contested case hearing with the WDNR in connection with the administrative order. The WDNR has granted that petition, but a hearing has not yet been scheduled. In addition, in May 2013, the WDNR referred the matter to the Wisconsin Department of Justice for alleged violations of air management statutes and rules. We could be subject to fines and penalties.

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

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 Section 1603 renewable energy grant related to the construction of our biomass facility in Rothschild, Wisconsin. We recorded a receivable for $82.6 million related to the grant that we expect to receive in the first half of 2014. The PSCW anticipated the recognition of this grant as income when it set rates for the two years beginning January 1, 2013. During 2013, we have provided bill credits to our Wisconsin electric customers which reflects the grant as income. The bill credits also reflect the tax benefits related to the grant. The bill credits will continue in 2014.

During 2013, we recognized the Treasury Grant as income, less the amounts that we have established as a deferred liability. The amount reflected in earnings matched the amount of the bill credits given to customers. The deferred balance reflects the amount of the grant income that we expect to benefit our customers in the future. This accounting reflects the regulatory treatment of the grant.

The PSCW approved escrow accounting treatment for the Treasury Grant. Under escrow accounting, we true-up any differences between the actual grant proceeds received and the grant proceeds passed on to customers in the form of bill credits.

Tangible Property Regulations:   During September 2013, the Treasury Department and IRS issued final regulations pertaining to costs incurred to acquire, maintain or improve tangible property. These regulations are generally effective for tax years beginning on or after January 1, 2014. We continue to evaluate what impact, if any, the adoption of the regulations will have on our consolidated financial statements; however, we do not currently expect the impact to be material.

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:

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Regulatory Accounting:Our utility subsidiaries 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, 2013, we had $1,108.5 million in regulatory assets and $879.1 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 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	$	5.2
0.5% decrease in expected rate of return on plan assets	$	6.6

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 demographics (age and compensation levels), our contributions to the plans, earnings on plan assets 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 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, the regulators of our utility segment have adopted accounting guidance for compensation related to retirement benefits for rate-making purposes.

70 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2013 Form 10-K

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	$	0.7
0.5% decrease in health care cost trend rate in all future years	$	(1.5	)
0.5% decrease in expected rate of return on plan assets	$	1.4

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 utility operating revenues during 2013 of approximately $4.5 billion included accrued utility revenues of $321.1 million as of December 31, 2013.

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 Wisconsin Energy and its subsidiaries are exposed.

71 Wisconsin Energy Corporation

2013 Form 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

WISCONSIN ENERGY CORPORATION
CONSOLIDATED INCOME STATEMENTS
Year Ended December 31
	2013		2012		2011
	(Millions of Dollars, Except Per Share Amounts)
Operating Revenues	$	4,519.0	$	4,246.4	$	4,486.4
Operating Expenses
Fuel and purchased power	1,153.0		1,098.6		1,169.7
Cost of gas sold	674.1		545.8		728.7
Other operation and maintenance	1,155.0		1,116.1		1,256.8
Depreciation and amortization	388.1		364.2		330.2
Property and revenue taxes	116.7		121.4		113.7
Total Operating Expenses	3,486.9		3,246.1		3,599.1
Treasury Grant	48.0		—		—
Operating Income	1,080.1		1,000.3		887.3
Equity in Earnings of Transmission Affiliate	68.5		65.7		62.5
Other Income and Deductions, net	18.8		34.8		62.7
Interest Expense, net	252.1		248.2		235.8
Income from Continuing Operations Before Income Taxes	915.3		852.6		776.7
Income Tax Expense	337.9		306.3		263.9
Income from Continuing Operations	577.4		546.3		512.8
Income from Discontinued Operations, Net of Tax	—		—		13.4
Net Income	$	577.4	$	546.3	$	526.2
Earnings Per Share (Basic)
Continuing Operations	$	2.54	$	2.37	$	2.20
Discontinued Operations	—		—		0.06
Total Earnings Per Share (Basic)	$	2.54	$	2.37	$	2.26
Earnings Per Share (Diluted)
Continuing Operations	$	2.51	$	2.35	$	2.18
Discontinued Operations	—		—		0.06
Total Earnings Per Share (Diluted)	$	2.51	$	2.35	$	2.24
Weighted Average Common Shares Outstanding (Millions)
Basic	227.6		230.2		232.6
Diluted	229.7		232.8		235.4
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

72 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
ASSETS
	2013			2012
	(Millions of Dollars)
Property, Plant and Equipment
In service	$	14,966.3		$	14,238.8
Accumulated depreciation	(4,257.1		)	(4,036.0		)
	10,709.2			10,202.8
Construction work in progress	149.6			315.9
Leased facilities, net	47.8			53.5
Net Property, Plant and Equipment	10,906.6			10,572.2
Investments
Equity investment in transmission affiliate	402.7			378.3
Other	36.1			35.5
Total Investments	438.8			413.8
Current Assets
Cash and cash equivalents	26.0			35.6
Accounts receivable, net of allowance for
doubtful accounts of $61.0 and $58.0	406.0			285.3
Accrued revenues	321.1			278.1
Materials, supplies and inventories	329.4			360.7
Current deferred tax asset, net	310.0			105.3
Prepayments	145.7			145.5
Other	12.9			62.1
Total Current Assets	1,551.1			1,272.6
Deferred Charges and Other Assets
Regulatory assets	1,108.5			1,380.3
Goodwill	441.9			441.9
Other	322.5			204.2
Total Deferred Charges and Other Assets	1,872.9			2,026.4
Total Assets	$	14,769.4		$	14,285.0
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

73 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
CAPITALIZATION AND LIABILITIES
	2013		2012
	(Millions of Dollars)
Capitalization
Common equity	$	4,233.0	$	4,135.1
Preferred stock of subsidiary	30.4		30.4
Long-term debt	4,363.2		4,453.8
Total Capitalization	8,626.6		8,619.3
Current Liabilities
Long-term debt due currently	342.2		412.1
Short-term debt	537.4		394.6
Accounts payable	342.6		368.4
Accrued payroll and benefits	96.9		100.9
Other	177.3		165.4
Total Current Liabilities	1,496.4		1,441.4
Deferred Credits and Other Liabilities
Regulatory liabilities	879.1		868.4
Deferred income taxes - long-term	2,634.0		2,117.0
Deferred revenue, net	664.2		709.7
Pension and other benefit obligations	173.2		244.0
Other long-term liabilities	295.9		285.2
Total Deferred Credits and Other Liabilities	4,646.4		4,224.3
Commitments and Contingencies (Note Q)
Total Capitalization and Liabilities	$	14,769.4	$	14,285.0
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

74 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
	2013			2012			2011
	(Millions of Dollars)
Operating Activities
Net income	$	577.4		$	546.3		$	526.2
Reconciliation to cash
Depreciation and amortization	400.2			371.7			336.4
Deferred income taxes and investment tax credits, net	312.7			293.2			430.6
Contributions to qualified benefit plans	—			(100.0		)	(277.4		)
Change in - Accounts receivable and accrued revenues	(162.9		)	38.3			30.1
Inventories	31.3			21.3			(2.9		)
Other current assets	2.8			12.1			(20.5		)
Accounts payable	(14.8		)	43.8			11.8
Accrued income taxes, net	36.6			116.9			(87.4		)
Deferred costs, net	(8.7		)	9.2			25.9
Other current liabilities	7.2			(14.9		)	44.1
Other, net	49.2			(164.0		)	(23.5		)
Cash Provided by Operating Activities	1,231.0			1,173.9			993.4
Investing Activities
Capital expenditures	(687.4		)	(707.0		)	(830.8		)
Investment in transmission affiliate	(10.5		)	(15.7		)	(6.6		)
Proceeds from asset sales	2.5			8.7			41.5
Change in restricted cash	2.7			42.8			(37.2		)
Cost of removal, net of salvage	(37.8		)	(38.3		)	(16.9		)
Other, net	(15.3		)	(20.1		)	(42.5		)
Cash Used in Investing Activities	(745.8		)	(729.6		)	(892.5		)
Financing Activities
Exercise of stock options	48.5			49.8			54.4
Purchase of common stock	(223.4		)	(153.2		)	(193.9		)
Dividends paid on common stock	(328.9		)	(276.3		)	(242.0		)
Issuance of long-term debt	251.0			251.8			720.0
Retirement of long-term debt	(397.2		)	(20.3		)	(466.6		)
Change in short-term debt	142.8			(275.3		)	12.0
Other, net	12.4			0.7			4.8
Cash Used in Financing Activities	(494.8		)	(422.8		)	(111.3		)
Change in Cash and Cash Equivalents	(9.6		)	21.5			(10.4		)
Cash and Cash Equivalents at Beginning of Year	35.6			14.1			24.5
Cash and Cash Equivalents at End of Year	$	26.0		$	35.6		$	14.1
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

75 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON EQUITY
	Common		Other Paid			Retained
	Stock		In Capital			Earnings			Total
	(Millions of Dollars)
Balance - December 31, 2010	$	2.3	$	721.5		$	3,078.3		$	3,802.1
Net income						526.2			526.2
Common stock cash
dividends of $1.04 per share						(242.0		)	(242.0		)
Exercise of stock options			54.4						54.4
Purchase of common stock			(193.9		)				(193.9		)
Tax benefit from share based compensation			11.9						11.9
Stock-based compensation and other			4.6						4.6
Balance - December 31, 2011	2.3		598.5			3,362.5			3,963.3
Net income						546.3			546.3
Common stock cash
dividends of $1.20 per share						(276.3		)	(276.3		)
Exercise of stock options			49.8						49.8
Purchase of common stock			(153.2		)				(153.2		)
Stock-based compensation and other			5.2						5.2
Balance - December 31, 2012	2.3		500.3			3,632.5			4,135.1
Net income						577.4			577.4
Common stock cash
dividends of $1.445 per share						(328.9		)	(328.9		)
Exercise of stock options			48.5						48.5
Purchase of common stock			(223.4		)				(223.4		)
Tax benefit from share based compensation			18.1						18.1
Stock-based compensation and other			6.2						6.2
Balance - December 31, 2013	$	2.3	$	349.7		$	3,881.0		$	4,233.0
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

76 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
		2013			2012
		(Millions of Dollars)
Common Equity (see accompanying statement)		$	4,233.0		$	4,135.1
Preferred Stock of Subsidiary (Note I)		30.4			30.4
Long-Term Debt
Wisconsin Energy Notes (unsecured)	6.20% due 2033	200.0			200.0
	6.25% Junior Notes due 2067	500.0			500.0
Wisconsin Electric Debentures (unsecured)	4.50% due 2013	—			300.0
	6.00% due 2014	300.0			300.0
	6.25% due 2015	250.0			250.0
	1.70% due 2018	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
	6-7/8% due 2095	100.0			100.0
Wisconsin Electric Notes (unsecured)	0.504% variable rate due 2016 (a)	67.0			67.0
	0.504% variable rate due 2030 (a)	80.0			80.0
	Variable rate notes	(147.0		)	(147.0		)
Wisconsin Gas Debentures (unsecured)	6.60% due 2013	—			45.0
	5.20% due 2015	125.0			125.0
	5.90% due 2035	90.0			90.0
We Power Subsidiary Notes (secured, nonrecourse)	4.91% due 2013-2030 (b)	122.1			126.7
	5.209% due 2013-2030 (c)	231.5			238.6
	4.673% due 2013-2031 (c)	190.9			196.7
	6.00% due 2013-2033 (b)	138.4			142.1
	6.09% due 2030-2040 (c)	275.0			275.0
	5.848% due 2031-2041 (c)	215.0			215.0
WECC Notes (unsecured)	6.51% due 2013	—			30.0
	6.94% due 2028	50.0			50.0
Other Notes (secured, nonrecourse)	6.00% due 2021	1.8			1.8
	4.81% effective rate due 2030	2.0			2.0
Obligations under capital leases		104.3			120.0
Unamortized discount, net and other		(25.6		)	(27.0		)
Long-term debt due currently		(342.2		)	(412.1		)
Total Long-Term Debt		4,363.2			4,453.8
Total Capitalization		$	8,626.6		$	8,619.3

(a) Variable interest rate as of December 31, 2013.

(b) Senior notes are secured by a collateral assignment of the leases between PWGS and Wisconsin Electric related to PWGS 1 and 2.

(c) Senior notes are secured by a collateral assignment of the leases between ERGSS and Wisconsin Electric related to OC 1 and 2.

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

77 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our subsidiaries in the following reportable segments:

• Utility Energy Segment -- Consisting of Wisconsin Electric and Wisconsin Gas, engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and

• Non-Utility Energy Segment -- Consisting primarily of We Power, engaged principally in the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Our Corporate and Other segment includes Wispark, which develops and invests in real estate. We have also eliminated all intercompany transactions 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.

Reclassifications and Adjustments:As of December 31, 2013, we have presented the tax effect of net operating loss carryforwards within current deferred tax assets, net on the consolidated balance sheets. As of December 31, 2012, $59.0 million representing the tax effect of net operating loss carryforwards were included in income taxes receivable, which is a line item that has now been condensed within other current assets on the consolidated balance sheets. This $59.0 million amount has been adjusted in the consolidated balance sheets as of December 31, 2012 to conform to the December 31, 2013 presentation, and conforming changes have been made in the consolidated statements of cash flows and in the notes to the consolidated financial statements. For additional information related to our deferred tax assets, see Note G.

In addition, we have adjusted the presentation of regulatory assets and liabilities to present amounts as noncurrent assets and liabilities on the consolidated balance sheets. Prior period amounts recorded within other current assets and liabilities have been reclassified to conform to the current presentation. For additional information related to regulatory assets and liabilities, see Note C.

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.

We recognize We Power revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease.

78 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

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	2013		2012			2011
	(Millions of Dollars)
AFUDC - Equity	$	18.3	$	35.3		$	59.4
Other, net	0.5		(0.5		)	3.3
Total Other Income and Deductions, net	$	18.8	$	34.8		$	62.7

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.

We recorded the following property in service by segment as of December 31:

Property In Service	2013		2012
	(Millions of Dollars)
Utility Energy	$	11,779.8	$	11,080.9
Non-Utility Energy	3,091.3		3,068.5
Other	95.2		89.4
Total	$	14,966.3	$	14,238.8

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 2013 and 2012, and 2.8% in 2011.

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.

Our regulated utilities collect in their 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 $724.5 million as of December 31, 2013 and $725.0 million as of December 31, 2012.

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2013		2012
	(Millions of Dollars)
Utility Energy	$	132.7	$	298.2
Non-Utility Energy	16.5		13.3
Other	0.4		4.4
Total	$	149.6	$	315.9

79 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Allowance For Funds Used During Construction - Regulated:   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.

Our regulated utility segment recorded the following AFUDC for the years ended December 31:

	2013		2012		2011
	(Millions of Dollars)
AFUDC - Debt	$	7.7	$	14.7	$	24.7
AFUDC - Equity	$	18.3	$	35.3	$	59.4

Capitalized Interest and Carrying Costs - Non-Regulated Energy:   As part of the construction of the PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheet and we are amortizing the deferred carrying costs to revenue over the individual lease terms.

Earnings per Common Share:   We compute basic earnings per common share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. All stock options outstanding during 2013, 2012 and 2011 were included in the computation of diluted earnings per share. Anti-dilutive shares are excluded from the calculation.

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

Materials, Supplies and Inventories	2013		2012
	(Millions of Dollars)
Fossil Fuel	$	117.7	$	165.5
Materials and Supplies	133.9		121.9
Natural Gas in Storage	77.8		73.3
Total	$	329.4	$	360.7

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.

80 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

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

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.

Goodwill:   Goodwill reflects the cost of an acquisition in excess of the fair values assigned to identifiable net assets acquired. As of December 31, 2013 and 2012, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.

Goodwill is not subject to amortization. However, it is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. Fair value is assessed by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2013 impairment test date.

Impairment or Disposal of Long Lived Assets:   We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2013, 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 26.2% in ATC as of December 31, 2013 and 2012. 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. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note G.

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.

81 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Stock Options:   We estimate the fair value of stock options using the binomial pricing model. We report unearned stock-based compensation associated with non-vested restricted stock and performance share awards activity within Other Paid in Capital in our Consolidated Statements of Common Equity. We report excess tax benefits as a financing cash inflow. 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 grant date. For a discussion of the impacts to our Consolidated Financial Statements, see Note H.

The fair value of our stock options was calculated using a binomial option-pricing model using the following weighted-average assumptions:

	2013	2012	2011
Risk-free interest rate	0.1% - 1.9%	0.1% - 2.0%	0.2% - 3.4%
Dividend yield	3.7%	3.9%	3.9%
Expected volatility	18.0%	19.0%	19.0%
Expected life (years)	5.9	5.9	5.5
Expected forfeiture rate	2.0%	2.0%	2.0%
Weighted-average fair value
of our stock options granted	$3.45	$3.34	$3.17

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 this will continue into 2014. As of December 31, 2013, $48.0 million was recognized as income, which reflects the amount that was returned to customers in the form of bill credits during the year. We recorded an $82.6 million receivable, and deferred the balance that we expect to benefit our customers in the future. The accounting reflects the regulatory treatment of the grant.

The PSCW approved escrow accounting treatment for the Treasury Grant. Under escrow accounting, we true-up any differences between the actual grant proceeds received and the grant proceeds passed on to customers in the form of bill credits.

B -- RECENT ACCOUNTING PRONOUNCEMENTS

Offsetting Assets and Liabilities: In January 2013, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2013-01, Disclosures about Offsetting Assets and Liabilities. The guidance requires enhanced disclosures about derivatives. Both gross and net information related to eligible transactions is required under the guidance. This guidance is effective for fiscal years and interim periods beginning on or after January 1, 2013, and must be applied retrospectively. We adopted this guidance on January 1, 2013, and applied it retrospectively. The adoption and retrospective application of this guidance did not have any material impact on our financial statements. See Note L -- Derivative Instruments for the enhanced disclosures.

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, 2013, we had $10.1 million of regulatory assets not earning a return and $82.7 million of regulatory assets earning a return based on short-term interest rates.

In December 2012, the PSCW issued a rate order effective January 1, 2013 that, among other things, reaffirmed our accounting for the regulatory assets and liabilities identified below.

82 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

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

	2013		2012
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	537.6	$	731.5
Deferred income tax related	169.5		176.5
Escrowed electric transmission costs	126.8		114.1
Escrowed conservation	66.9		73.5
Deferred plant related -- capital lease	56.5		66.6
Deferred environmental costs	47.0		47.4
Other, net	104.2		170.7
Total regulatory assets	$	1,108.5	$	1,380.3
Regulatory Liabilities
Deferred cost of removal obligations	$	724.5	$	725.0
Escrowed bad debt costs	64.6		81.1
Other, net	90.0		62.2
Total regulatory liabilities	$	879.1	$	868.3

D -- ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

The following table summarizes the net impacts of the discontinued operations on our earnings for the years ended December 31:

	2013		2012		2011
	(Millions of Dollars)
Income from Continuing Operations	$	577.4	$	546.3	$	512.8
Income from Discontinued other operations, net of tax (a)	—		—		13.4
Net Income	$	577.4	$	546.3	$	526.2

(a) Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

Edgewater Generating Unit 5:   On March 1, 2011, we sold our 25% interest in Edgewater Generating Unit 5 to WPL for our net book value, including working capital, of approximately $38 million. This transaction was treated as a sale of an asset.

83 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 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 2013 and 2012:

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	44.3		$	55.5
Liabilities Settled	(4.4		)	(14.0		)
Accretion	2.4			2.8
Balance as of December 31	$	42.3		$	44.3

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 nine years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.

We have approximately $215.9 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 2013, 2012 and 2011 were $50.3 million, $45.8 million and $65.9 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	2013			2012			2011
	(Millions of Dollars)
Current tax expense (benefit)	$	25.2		$	13.1		$	(166.7	)
Deferred income taxes, net	313.8			294.4			434.8
Investment tax credit, net	(1.1		)	(1.2		)	(4.2		)
Total Income Tax Expense	$	337.9		$	306.3		$	263.9

84 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 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 as a result of the following:

	2013					2012					2011
				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	$	320.3		35.0	%	$	298.4		35.0	%	$	271.8		35.0	%
State income taxes net of federal tax benefit	49.0			5.3	%	43.3			5.1	%	40.1			5.2	%
Production tax credits	(16.7		)	(1.8	)%	(15.9		)	(1.9	)%	(8.7		)	(1.1	)%
Treasury Grant	(7.4		)	(0.8	)%	—			—	%	—			—	%
AFUDC - Equity	(6.4		)	(0.7	)%	(12.3		)	(1.4	)%	(20.8		)	(2.7	)%
Investment tax credit restored	(1.1		)	(0.1	)%	(1.2		)	(0.1	)%	(4.2		)	(0.5	)%
Domestic production activities deduction	—			—	%	(12.6		)	(1.5	)%	(12.6		)	(1.6	)%
Other, net	0.2			—	%	6.6			0.7	%	(1.7		)	(0.3	)%
Total Income Tax Expense	$	337.9		36.9	%	$	306.3		35.9	%	$	263.9		34.0	%

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	2013		2012
	(Millions of Dollars)
Current
Future federal tax benefits	$	309.7	$	59.0
Employee benefits and compensation	13.8		14.9
Other	56.0		81.1
Total Current Deferred Tax Assets	379.5		155.0
Non-current
Deferred revenues	237.0		250.0
Employee benefits and compensation	95.6		97.0
Future federal tax benefits	32.5		334.7
Property-related	28.2		28.3
Construction advances	18.3		22.2
Other	62.9		16.3
Total Non-Current Deferred Tax Assets	474.5		748.5
Total Deferred Tax Assets	$	854.0	$	903.5

85 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Deferred Tax Liabilities	2013		2012
	(Millions of Dollars)
Current
Prepaid items	$	69.5	$	49.7
Total Current Deferred Tax Liabilities	69.5		49.7
Non-current
Property-related	2,574.4		2,339.4
Employee benefits and compensation	238.5		244.3
Investment in transmission affiliate	169.9		144.9
Deferred transmission costs	50.8		45.7
Other	74.9		91.2
Total Non-current Deferred Tax Liabilities	3,108.5		2,865.5
Total Deferred Tax Liabilities	$	3,178.0	$	2,915.2
Consolidated Balance Sheet Presentation	2013		2012
Current Deferred Tax Asset	$	310.0	$	105.3
Non-Current Deferred Tax Liability	$	2,634.0	$	2,117.0

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, 2013, we had approximately $810.3 million and $58.6 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of $283.6 million and $58.6 million, respectively. As of December 31, 2012, we had approximately $1,007.1 million and $41.2 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of $352.5 million and $41.2 million, respectively. The tax credit and net operating loss carryforwards begin to expire in 2029. 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:

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	11.3		$	11.1
Additions for tax positions of prior years	—			10.8
Reductions for tax positions of prior years	(2.9		)	(10.6		)
Balance as of December 31	$	8.4		$	11.3

The amount of unrecognized tax benefits as of December 31, 2013 and 2012 excludes deferred tax assets related to uncertainty in income taxes of $8.4 million and $10.2 million, respectively. As of December 31, 2013, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations. As of December 31, 2012, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $1.0 million.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2013, 2012 and 2011, we recognized approximately $0.2 million, $0.2 million and $0.7 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2013 and 2012, we recognized no penalties in the Consolidated Income Statements. For the year ended 2011, we recognized a benefit of $0.3 million in the Consolidated Income Statements related to a reduction of accrued penalties. We had approximately $0.4 million and $0.3 million of interest accrued and no penalties accrued on the Consolidated Balance Sheets as of December 31, 2013 and 2012, respectively.

86 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

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

Our primary tax jurisdictions include the United States and the state of Wisconsin. Currently, the tax years of 2011 through 2013 are subject to Federal examination, and the tax years 2009 through 2013 are subject to examination by the state of Wisconsin.

H -- COMMON EQUITY

As of December 31, 2013 and 2012, we had 325,000,000 shares of common stock authorized under our charter, of which 225,962,959 and 229,039,456 common shares, respectively, were outstanding. All share-based compensation is currently fulfilled by purchases on the open market by our independent agents and do not dilute shareholders' ownership.

Share-Based Compensation Plans:   We have a plan that was approved by stockholders that enables us to provide a long-term incentive through equity interests in Wisconsin Energy to outside directors, selected officers and key employees of the Company. The plan provides for the granting of stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in 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 stock options during the period.

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors as of December 31:

	2013		2012		2011
	(Millions of Dollars)
Performance units	$	12.7	$	16.3	$	24.1
Stock options	3.9		2.7		2.6
Restricted stock	2.4		3.0		1.8
Share-based compensation expense	$	19.0	$	22.0	$	28.5
Related Tax Benefit	$	7.6	$	8.8	$	11.4

Stock Options:   The exercise price of a 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 our stock options, see Note A.

We expect that substantially all of the outstanding options as of December 31, 2013 will be exercised.

87 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

The following is a summary of our stock option activity during 2013:

Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of January 1, 2013	8,919,669		$	23.86
Granted	1,418,560		$	37.46
Exercised	(2,238,489	)	$	21.67
Forfeited	(10,030	)	$	35.37
Outstanding as of December 31, 2013	8,089,710		$	26.84	5.4	$	117.3
Exercisable as of December 31, 2013	5,708,920		$	23.16	4.1	$	103.8

In January 2014, the Compensation Committee of the Board of Directors (Compensation Committee) awarded 899,500 non-qualified stock options with an exercise price of $41.03 to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

The intrinsic value of options exercised during the years ended December 31, 2013, 2012 and 2011 was $44.5 million, $47.5 million and $36.1 million, respectively. Cash received from options exercised during the years ended December 31, 2013, 2012 and 2011 was $48.5 million, $49.8 million and $54.4 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $17.8 million, zero and $14.3 million, respectively.

The following table summarizes information about stock options outstanding as of December 31, 2013:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
Range of Exercise Prices	Number of Options	Exercise Price		Remaining Contractual Life (Years)	Number of Options	Exercise Price		Remaining Contractual Life (Years)
$16.72  to  $21.11	2,128,370	$	20.34	3.9	2,128,370	$	20.34	3.9
$23.88  to  $29.35	3,689,900	$	24.65	4.2	3,382,630	$	24.23	4.0
$34.88  to  $37.46	2,271,440	$	36.48	8.6	197,920	$	35.19	8.1
	8,089,710	$	26.84	5.4	5,708,920	$	23.16	4.1

The following table summarizes information about our non-vested options during 2013:

Non-Vested Stock Options	Number of Options		Weighted- Average Fair Value
Non-Vested as of January 1, 2013	1,702,275		$	3.31
Granted	1,418,560		$	3.45
Vested	(730,015	)	$	3.34
Forfeited	(10,030	)	$	3.37
Non-Vested as of December 31, 2013	2,380,790		$	3.38

As of December 31, 2013, total compensation costs related to non-vested stock options not yet recognized was approximately $2.0 million, which is expected to be recognized over the next 21 months on a weighted-average basis.

88 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Restricted Shares:   The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2013:

Restricted Shares	Number of Shares		Weighted-Average Market Price
Outstanding as of January 1, 2013	188,222
Granted	74,290		$	37.65
Released	(97,973	)	$	26.65
Forfeited	(13,841	)	$	33.35
Outstanding as of December 31, 2013	150,698

In January 2014, the Compensation Committee awarded 71,504 restricted shares to our directors, officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and generally, 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.

We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards. The intrinsic value of restricted stock vesting was $4.0 million, $3.5 million and $2.5 million for the years ended December 31, 2013, 2012, and 2011, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $1.3 million, zero and $0.8 million, respectively.

As of December 31, 2013, total compensation cost related to restricted stock not yet recognized was approximately $2.6 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Performance Units:   In January 2013, 2012 and 2011, the Compensation Committee awarded 239,120, 346,570 and 435,690 performance units, respectively, to 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 our 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 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, 2013, 2012 and 2011 vested and were settled during the first quarter of 2014, 2013 and 2012, and had a total intrinsic value of $14.8 million, $19.3 million and $26.7 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $5.3 million, $7.0 million and $9.7 million, respectively.

In January 2014, the Compensation Committee awarded 233,735 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

As of December 31, 2013, total compensation cost related to performance units not yet recognized was approximately $10.8 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Restrictions:Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from its non-utility subsidiary, We Power, and its utility subsidiaries.

Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.

Wisconsin Electric and Wisconsin Gas are required to maintain capital structures that differ from GAAP as they reflect regulatory adjustments. The 2013 PSCW rate case order requires Wisconsin Electric to maintain a common equity ratio range of between 48.5% and 53.5%, and Wisconsin Gas to maintain a capital structure which has a common equity range of between 45.0% and 50.0%. Each company is in compliance with its respective common

89 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

equity range. Wisconsin Electric and Wisconsin Gas must obtain PSCW approval if they pay dividends above the test year levels that would cause either company to fall below the authorized levels of common equity.

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

We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

As of December 31, 2013, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method total approximately $3.6 billion. This amount exceeds 25% of our consolidated net assets as of December 31, 2013.

See Note K for discussion of certain financial covenants related to the bank back-up credit facilities of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.

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

Share Repurchase Program:  We do not expect to issue new shares under our various employee benefit plans and our dividend reinvestment and share purchase plan; rather, we instruct independent plan agents to purchase the shares in the open market. In that regard, no new shares of common stock were issued in 2013, 2012 or 2011.

In May 2011, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock through the end of 2013. Through December 31, 2013, we repurchased approximately 7.7 million shares pursuant to this program at an average cost of $36.19 per share and a total cost of $277.8 million. In addition, through our independent agents, we purchase shares on the open market to fulfill exercised stock options and restricted stock awards. The following table identifies the shares purchased by the Company for the year ending December 31:

	2013			2012			2011
	Shares	Cost		Shares	Cost		Shares	Cost
	(In Millions)
Under May 2011 share repurchase program	3.0	$	126.0	1.5	$	51.8	3.2	$	100.0
To fulfill exercised stock options and restricted stock awards	2.4	97.4		2.8	101.4		3.0	93.9
Total	5.4	$	223.4	4.3	$	153.2	6.2	$	193.9

On December 5, 2013, our Board of Directors authorized a new share repurchase program for management to purchase up to $300 million of the Company's common stock through open market purchases or privately negotiated transactions from January 1, 2014 through the end of 2017. The repurchase program does not obligate Wisconsin Energy to acquire any specific number of shares and may be suspended or terminated by the Board of Directors at any time.

90 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

I -- PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2013 and 2012:

	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
					(In Millions)
Wisconsin Energy
$.01 par value Preferred Stock	15,000,000	—	—		$	—
Wisconsin Electric
$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 of subsidiary					$	30.4

J -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

Debentures and Notes:   As of December 31, 2013, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:

	(Millions of Dollars)
2014	$	322.4
2015	399.5
2016	27.4
2017	29.5
2018	281.1
Thereafter	3,566.8
Total	$	4,626.7

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

Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2013 and 2012, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

In connection with our outstanding Junior Notes, we executed the Replacement Capital Covenant dated May 11, 2007 (RCC) for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.

Obligations Under Capital Leases:   In 1997, Wisconsin Electric 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, Wisconsin

91 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Electric may, at its option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and 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.

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $33.7 million and $32.5 million in lease payments during 2013 and 2012, respectively. 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 lease in Note C). Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $104.3 million as of December 31, 2013, and will decrease to zero over the remaining life of the contract.

The following is a summary of our capitalized leased facilities as of December 31:

Capital Lease Assets	2013			2012
	(Millions of Dollars)
Leased Facilities
Long-term power purchase commitment	$	140.3		$	140.3
Accumulated amortization	(92.5		)	(86.8		)
Total Leased Facilities	$	47.8		$	53.5

Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2013 are as follows:

	(Millions of Dollars)
2014	$	41.9
2015	43.5
2016	45.1
2017	13.9
2018	14.7
Thereafter	56.8
Total Minimum Lease Payments	215.9
Less:  Estimated Executory Costs	(61.7		)
Net Minimum Lease Payments	154.2
Less:  Interest	(49.9		)
Present Value of Net
Minimum Lease Payments	104.3
Less:  Due Currently	(19.8		)
	$	84.5

92 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

K -- SHORT-TERM DEBT

Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

	2013				2012
			Interest				Interest
Short-Term Debt	Balance		Rate		Balance		Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	537.4	0.20	%	$	394.6	0.30	%

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

	2013			2012
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$	594.5		$	669.9
Average Short-Term Debt Outstanding	$	359.1		$	481.6
Weighted-Average Interest Rate	0.25		%	0.28		%

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require the companies to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.

As of December 31, 2013, we had approximately $1.2 billion of available undrawn lines under our bank back-up credit facilities and $537.4 million of commercial paper outstanding that was supported by the available lines of credit. Our bank back-up credit facilities expire in December 2017.

The Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control. In addition, pursuant to the terms of Wisconsin Energy's credit agreement, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein.

As of December 31, 2013, 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 and shareholders. 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, 2013, we recognized $0.3 million in regulatory assets and $9.6 million in regulatory liabilities related to derivatives in comparison to $7.6 million in regulatory assets and $17.5 million in regulatory liabilities as of December 31, 2012.

93 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

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 $0.4 million is recorded in other deferred charges and other assets, and we had no long-term portion of derivative liabilities. Our Consolidated Balance Sheets as of December 31, 2013 and 2012 include:

	December 31, 2013				December 31, 2012
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	5.6	$	0.1	$	3.0	$	1.9
Fuel Oil	0.6		—		0.4		—
FTRs	3.5		—		4.7		—
Coal	2.1		0.2		11.1		—
Total	$	11.8	$	0.3	$	19.2	$	1.9

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 were as follows:

	2013				2012
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	48.6 million Dth	$	(8.5	)	77.2 million Dth	$	(36.3	)
Fuel Oil	8.6 million gallons	0.5			7.0 million gallons	1.8
FTRs	25.3 million MWh	14.9			25.1 million MWh	6.1
Total		$	6.9			$	(28.4	)

As of December 31, 2013 and 2012, we posted collateral of zero and $2.9 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

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

	2013				2012
	Derivative		Derivative		Derivative			Derivative
	Asset		Liability		Asset			Liability
	(Millions of Dollars)
Gross Amount Recognized on the Balance Sheet	$	11.8	$	0.3	$	19.2		$	1.9
Gross Amount Not Offset on Balance Sheet (a)	—		—		(0.5		)	(1.8		)
Net Amount	$	11.8	$	0.3	$	18.7		$	0.1

(a) Gross Amount Not Offset on Balance Sheet includes cash collateral posted of zero and $1.3 million as of December 31, 2013 and 2012, respectively.

94 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

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 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, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	5.7	$	2.6	$	3.5	11.8
Total	$	5.7	$	2.6	$	3.5	$	11.8
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

95 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Recurring Fair Value Measures	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	2.7	$	—	$	—	$	2.7
Derivatives	2.2		12.3		4.7		19.2
Total	$	4.9	$	12.3	$	4.7	$	21.9
Liabilities:
Derivatives	$	1.9	$	—	$	—	$	1.9
Total	$	1.9	$	—	$	—	$	1.9

We adopted ASU 2013-01, Disclosures about Offsetting Assets and Liabilities, on a retrospective basis. For additional information, see Note B -- Recent Accounting Pronouncements and Note L -- Derivative Instruments.

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

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

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	4.7		$	5.7
Realized and unrealized gains (losses)	—			—
Purchases	10.6			11.0
Issuances	—			—
Settlements	(11.8		)	(12.0		)
Transfers in and/or out of Level 3	—			—
Balance as of December 31	$	3.5		$	4.7
Change in unrealized gains (losses) relating to instruments still held as of December 31	$	—		$	—

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.

96 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2013				2012
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	26.0	$	30.4	$	26.0
Long-term debt including current portion	$	4,626.7	$	4,911.8	$	4,772.9	$	5,447.3

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 have 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.

We also have OPEB plans covering 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.

We use a year-end measurement date to measure the funded status of all of our 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 our pension and OPEB plans qualify as a regulatory asset.

97 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

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

	Pension						OPEB
	2013			2012			2013			2012
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,508.5		$	1,330.6		$	381.2		$	389.7
Service cost	14.6			21.7			10.0			10.3
Interest cost	60.4			65.5			15.6			20.3
Participants' contributions	—			—			8.9			9.6
Plan amendments	(1.0		)	—			—			0.5
Actuarial loss (gain)	(81.9		)	166.5			(27.7		)	(23.8		)
Other accrued benefits	—			31.4			—			—
Gross benefits paid	(90.4		)	(107.2		)	(26.3		)	(26.3		)
Federal subsidy on benefits paid	N/A			N/A			1.0			0.9
Benefit Obligation at December 31	$	1,410.2		$	1,508.5		$	362.7		$	381.2
Change in Plan Assets
Fair Value at January 1	$	1,385.4		$	1,262.5		$	285.4		$	255.4
Actual earnings on plan assets	147.3			127.4			45.5			29.0
Employer contributions	8.7			102.7			14.1			17.7
Participants' contributions	—			—			8.9			9.6
Gross benefits paid	(90.4		)	(107.2		)	(26.3		)	(26.3		)
Fair Value at December 31	$	1,451.0		$	1,385.4		$	327.6		$	285.4
Net asset (liability)	$	40.8		$	(123.1	)	$	(35.1	)	$	(95.8	)

As of December 31, 2013, our qualified pension plan was over-funded by $138.7 million and our non-qualified pension plan was under-funded by $97.9 million. As of December 31, 2012, our qualified and non-qualified pension plans were under-funded by $20.9 million and $102.2 million, respectively.

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

	Pension				OPEB
	2013		2012		2013		2012
	(Millions of Dollars)
Other long-term assets	$	138.7	$	—	$	40.2	$	25.1
Other long-term liabilities	$	97.9	$	123.1	$	75.3	$	120.9

The accumulated benefit obligation for all defined pension plans was $1,409.5 million and $1,507.1 million as of December 31, 2013, and 2012, respectively.

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
	2013		2012		2013			2012
	(Millions of Dollars)
Net actuarial loss	$	528.8	$	719.2	$	9.8		$	65.3
Prior service costs (credits)	8.8		12.2		(1.7		)	(3.7		)
Total - Regulatory Assets	$	537.6	$	731.4	$	8.1		$	61.6

98 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

We estimate that 2014 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs (credits) referred to above of $38.7 million and $(0.9) million, respectively.

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

	Pension									OPEB
	2013			2012			2011			2013			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	14.6		$	21.7		$	15.9		$	10.0		$	10.3		$	10.4
Interest cost	60.4			65.5			67.6			15.6			20.3			20.8
Expected return on plan assets	(95.8		)	(89.6		)	(82.1		)	(21.3		)	(19.0		)	(16.9		)
Amortization of:
Transition obligation	—			—			—			—			0.3			0.3
Prior service cost (credit)	2.3			2.2			2.2			(2.0		)	(1.9		)	(1.9		)
Actuarial loss	54.5			41.0			34.0			3.7			7.3			6.2
Settlement charge	2.5			—			—			—			—			—
Other	—			0.4			—			—			—			—
Net Periodic Benefit Cost	$	38.5		$	41.2		$	37.6		$	6.0		$	17.3		$	18.9

	Pension			OPEB
	2013	2012	2011	2013	2012	2011
Weighted-Average assumptions used to
determine benefit obligations as of Dec. 31
Discount rate	5.00%	4.10%	5.05%	4.95%	4.15%	5.20%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A
Weighted-Average assumptions used to
determine net cost for year ended Dec. 31
Discount rate	4.10%	5.05%	5.60%	4.15%	5.20%	5.70%
Expected return on plan assets	7.25%	7.25%	7.25%	7.50%	7.50%	7.50%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A

Assumed health care cost trend rates as of Dec. 31	2013	2012	2011
Health care cost trend rate assumed for next year (Pre 65 / Post 65)	7.5%/7.5%	7.5%/7.5%	8.0%/12%
Rate that the cost trend rate gradually adjusts to	5.0%	5.0%	5.0%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)	2021/2021	2017/2017	2017/2017

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2013, 2012 and 2011. We consult with our investment advisors on an annual basis to help us 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.

99 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 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	$	26.4	$	(22.3	)
Total of service and interest cost components	$	3.2	$	(2.6	)

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.

Our current pension plan target asset allocation is 45% equity investments and 55% fixed income 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 pension plan assets by asset category within the fair value hierarchy (for further level information, see Note M):

	As of December 31, 2013
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	21.0	$	—	$	—	$	21.0
Equities:
U.S. Equity	519.5		—		—		519.5
International Equity	146.2		35.7		—		181.9
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	108.4		505.2		—		613.6
International Bonds	78.1		36.9		—		115.0
Total	$	873.2	$	577.8	$	—	$	1,451.0

100 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

	As of December 31, 2012
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	13.7	$	—	$	—	$	13.7
Equities:
U.S. Equity	466.3		—		—		466.3
International Equity	134.7		30.4		—		165.1
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	67.7		546.6		—		614.3
International Bonds	80.7		45.3		—		126.0
Total	$	763.1	$	622.3	$	—	$	1,385.4

(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 OPEB plan assets by asset category within the fair value hierarchy:

	As of December 31, 2013
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	2.6	$	—	$	—	$	2.6
Equities:
U.S. Equity	148.0		—		—		148.0
International Equity	46.9		2.8		—		49.7
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	8.4		96.3		—		104.7
International Bonds	16.8		5.8		—		22.6
Total	$	222.7	$	104.9	$	—	$	327.6

	As of December 31, 2012
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	1.7	$	—	$	—	$	1.7
Equities:
U.S. Equity	125.9		—		—		125.9
International Equity	39.9		2.2		—		42.1
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	5.0		89.9		—		94.9
International Bonds	15.4		5.4		—		20.8
Total	$	187.9	$	97.5	$	—	$	285.4

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

101 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Cash Flows:   

Historical employer contributions:

	Pension
Year	Qualified		Non-Qualified		OPEB
	(Millions of Dollars)
2011	$	236.4	$	6.5	$	48.4
2012	$	95.6	$	7.1	$	17.7
2013	$	—	$	8.7	$	14.1

Estimated benefit payments:

Year	Pension		Gross OPEB
	(Millions of Dollars)
2014	$	103.9	$	24.2
2015	$	98.6	$	21.6
2016	$	100.3	$	22.0
2017	$	100.9	$	22.6
2018	$	100.2	$	23.4
2019-2023	$	495.6	$	119.7

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 $14.2 million, $13.8 million and $14.1 million during 2013, 2012 and 2011, respectively.

Postemployment Benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $4.2 million and $4.0 million as of December 31, 2013 and 2012, respectively.

O -- SEGMENT REPORTING

Our reportable segments as of December 31, 2013 include a utility energy segment and a non-utility energy segment. We have organized our reportable segments based upon the regulatory environment in which our utility subsidiaries operate and on how management makes decisions and measures performance. The segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation 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 operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

102 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Summarized financial information concerning our reportable segments for each of the three years ended December 31, 2013 is shown in the following table.

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2013
Operating Revenues (b)	$	4,462.0	$	446.7	$	1.3		$	(391.0	)	$	4,519.0
Depreciation and Amortization	$	320.2	$	67.1	$	0.8		$	—		$	388.1
Operating Income (Loss)	$	719.4	$	367.1	$	(6.4	)	$	—		$	1,080.1
Equity in Earnings of Unconsolidated Affiliates	$	68.5	$	—	$	(0.1	)	$	—		$	68.4
Interest Expense, Net	$	136.2	$	65.7	$	50.8		$	(0.6	)	$	252.1
Income Tax Expense (Benefit)	$	243.6	$	120.2	$	(25.9	)	$	—		$	337.9
Net Income (Loss)	$	425.1	$	181.6	$	577.2		$	(606.5	)	$	577.4
Capital Expenditures	$	657.9	$	26.1	$	3.4		$	—		$	687.4
Total Assets (c)	$	14,460.4	$	2,846.5	$	4,719.5		$	(7,257.0	)	$	14,769.4

December 31, 2012
Operating Revenues (b)	$	4,190.8	$	439.9	$	1.2		$	(385.5	)	$	4,246.4
Depreciation and Amortization	$	296.4	$	67.1	$	0.7		$	—		$	364.2
Operating Income (Loss)	$	647.7	$	358.8	$	(6.2	)	$	—		$	1,000.3
Equity in Earnings of Unconsolidated Affiliates	$	65.7	$	—	$	(0.2	)	$	—		$	65.5
Interest Expense, Net	$	129.4	$	66.7	$	52.5		$	(0.4	)	$	248.2
Income Tax Expense (Benefit)	$	214.9	$	116.6	$	(25.2	)	$	—		$	306.3
Net Income (Loss)	$	400.6	$	175.9	$	546.1		$	(576.3	)	$	546.3
Capital Expenditures	$	697.3	$	5.5	$	4.2		$	—		$	707.0
Total Assets (c)	$	13,988.1	$	2,903.5	$	4,431.4		$	(7,038.0	)	$	14,285.0

December 31, 2011
Operating Revenues (b)	$	4,431.5	$	435.1	$	0.9		$	(381.1	)	$	4,486.4
Depreciation and Amortization	$	257.0	$	72.5	$	0.7		$	—		$	330.2
Operating Income (Loss)	$	544.8	$	348.9	$	(6.4	)	$	—		$	887.3
Equity in Earnings of Unconsolidated Affiliates	$	62.5	$	—	$	(0.9	)	$	—		$	61.6
Interest Expense, Net	$	110.0	$	66.7	$	59.5		$	(0.4	)	$	235.8
Income Tax Expense (Benefit)	$	182.7	$	112.8	$	(31.6	)	$	—		$	263.9
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	13.4		$	—		$	13.4
Net Income (Loss)	$	376.3	$	169.8	$	525.9		$	(545.8	)	$	526.2
Capital Expenditures	$	792.2	$	31.2	$	7.4		$	—		$	830.8
Total Assets (c)	$	13,433.5	$	2,949.0	$	4,694.8		$	(7,215.2	)	$	13,862.1

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

(c) An elimination of $2,231.2 million, $2,286.7 million and $2,369.0 million is included in Total Assets as of December 31, 2013, 2012 and 2011, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

103 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

P -- RELATED PARTIES

We receive and/or provide certain services to other associated companies in which we have an equity investment.

American Transmission Company LLC:   As of December 31, 2013, we have a 26.2% 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, including the generating units constructed as part of our PTF strategy. ATC reimburses us for these costs when new generation is placed in service.

The following table summarizes material related party transactions with ATC during 2013, 2012 and 2011:

Equity Investee	2013		2012		2011
	(Millions of Dollars)
Equity in Earnings	$	68.5	$	65.7	$	62.5
Distributions Received	$	54.5	$	52.6	$	49.7
Services Provided	$	9.0	$	8.2	$	10.8
Services Received	$	234.2	$	222.7	$	219.2

As of December 31, 2013 and 2012, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:

Equity Investee	2013		2012
	(Millions of Dollars)
Accounts Receivable
Services provided	$	0.6	$	0.5
Accounts Payable
Services received	$	19.5	$	18.6

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)
2014	$	3.9
2015	3.9
2016	3.7
2017	3.1
2018	3.2
Thereafter	22.7
Total	$	40.5

104 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

Divested Assets:   Pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to WPL 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 manufactured gas plant sites and related disposal sites used by Wisconsin Electric and Wisconsin Gas, and coal combustion product disposal/landfill sites used by Wisconsin Electric, as discussed below. 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 Wisconsin Electric, Wisconsin Gas, 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 $19 million to $56 millionover 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, 2013 and 2012, we established reserves of $36.9 million and $38.2 million, respectively, related to future remediation costs.

Historically, the PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, 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:   Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its 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 Wisconsin Electric has 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 2013, 2012 and 2011, Wisconsin Electric incurred $0.1 million, $0.3 million and $0.2 million respectively, in landfill remediation expenses. As of December 31, 2013, 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. Sierra Club and Clean Wisconsin requested and were granted an administrative hearing before the WDNR on certain conditions of the permit; however, the case has been stayed. In addition, 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 either proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

In August 2012, we announced plans to convert the fuel source for VAPP from coal to natural gas and anticipate that the conversion will be completed by the end of 2015 or early 2016. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC. We filed for a Certificate of Authority from the PSCW on April 26, 2013, and received preliminary approval on January 30, 2014. We expect to receive a final written order by the end of the first quarter. We received a construction air permit from the WDNR on November 11, 2013.

105 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

R -- SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2013, we paid $250.4 million in interest, net of amounts capitalized, and received $39.6 million in net refunds from income taxes. During the year ended December 31, 2012, we paid $241.2 million in interest, net of amounts capitalized, and received $107.0 million in net refunds from income taxes. During the year ended December 31, 2011, we paid $234.0 million in interest, net of amounts capitalized, and received $109.1 million in net refunds from income taxes.

As of December 31, 2013, 2012 and 2011, the amount of accounts payable related to capital expenditures was $4.7 million, $15.7 million and $16.7 million, respectively.

During the years ended December 31, 2013, 2012 and 2011, total amortization of deferred revenue was $56.5 million, $54.9 million and $54.4 million, respectively.

During the year ended December 31, 2013, we recorded an $82.6 million receivable related to the Treasury Grant. In conjunction with this transaction, we recognized $48.0 million as income, and deferred the balance.

106 Wisconsin Energy Corporation

2013 Form 10-K

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Energy Corporation:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2013 and 2012, 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, 2013. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 Energy Corporation and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2014 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 27, 2014

107 Wisconsin Energy Corporation

2013 Form 10-K

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Energy Corporation:

We have audited the internal control over financial reporting of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the 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.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2013 of the Company and our report dated February 27, 2014 expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 27, 2014

108 Wisconsin Energy Corporation

2013 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 Energy Corporation's and subsidiaries' internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that Wisconsin Energy Corporation's and subsidiaries' internal control over financial reporting was effective as of December 31, 2013.

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.

Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our financial statements has issued an attestation report on the effectiveness of Wisconsin Energy Corporation's and its subsidiaries' internal control over financial reporting as of December 31, 2013. Deloitte & Touche LLP's report is included in this report.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

109 Wisconsin Energy Corporation

2013 Form 10-K

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT

The information under "Proposal 1: Election of Directors - Terms Expiring in 2015", "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 the Corporate Governance Committee?", "Corporate Governance - Frequently Asked Questions: Are the Audit and Oversight, Corporate Governance 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'?" and "Committees of the Board of Directors - Audit and Oversight" in our Definitive Proxy Statement on Schedule 14A to be filed with the SEC for our Annual Meeting of Stockholders to be held May 2, 2014 (the "2014 Annual Meeting Proxy Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.

We have adopted a written code of ethics, referred to as our Code of Business Conduct, that all of our directors, executive officers and employees, including the principal executive officer, principal financial officer and principal accounting officer, must comply with. We have posted our Code of Business Conduct on our website, www.wisconsinenergy.com. We have 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 our website or in a current report on Form 8-K.

Our website, www.wisconsinenergy.com, also contains our Corporate Governance Guidelines and the charters of our Audit and Oversight, Corporate Governance and Compensation Committees.

Our Code of Business Conduct, Corporate Governance Guidelines and committee charters are also available without charge to any stockholder of record or beneficial owner of our common stock by writing to the corporate secretary, Susan H. Martin, at our principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.

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 2014 Annual Meeting Proxy Statement is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The security ownership information called for by Item 12 of Form 10-K is incorporated herein by reference to this information included under "WEC Common Stock Ownership" in the 2014 Annual Meeting Proxy Statement.

110 Wisconsin Energy Corporation

2013 Form 10-K

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth information about our equity compensation plans as of December 31, 2013:

	(a)	(b)		(c)
	Number of			Number of securities
	securities to be	Weighted average		remaining available for
	issued upon exercise	exercise price of		future issuance under equity
	of outstanding options,	outstanding options,		compensation plans (excluding
Plan Category	warrants and rights	warrants and rights		securities reflected in column (a))
Equity compensation plans approved by security holders	8,089,710	$	26.84	31,880,816	(1	)
Equity compensation plans not approved by security holders	—	—		—
Total	8,089,710	$	26.84	31,880,816
(1) Includes shares available for future issuance under our 1993 Omnibus Stock Incentive Plan, amended and restated
effective May 5, 2011, all of which could be granted as awards of stock options, stock appreciation rights, performance
units, restricted stock or other stock based awards.

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, Corporate Governance 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 2014 Annual Meeting Proxy 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 our Corporate Governance Guidelines, which can be found on our 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 2014 Annual Meeting Proxy Statement is incorporated herein by reference.

111 Wisconsin Energy Corporation

2013 Form 10-K

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, 2013.	72
Consolidated Balance Sheets at December 31, 2013 and 2012.	73
Consolidated Statements of Cash Flows for the three years ended December 31, 2013.	75
Consolidated Statements of Common Equity for the three years ended December 31, 2013.	76
Consolidated Statements of Capitalization at December 31, 2013 and 2012.	77
Notes to Consolidated Financial Statements.	78
Reports of Independent Registered Public Accounting Firm.	107

2. FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT

Schedule I, Condensed Parent Company Financial Statements, including Income Statements and Cash Flows for the three years ended December 31, 2013 and Balance Sheets as of December 31, 2013 and 2012.

Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2013.

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.

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.

112 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION

INCOME STATEMENTS

(Parent Company Only)

SCHEDULE I -- CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS

	Year Ended December 31
	2013			2012			2011
	(Millions of Dollars)
Other Income, Net	$	3.1		$	3.2		$	2.7
Corporate Expense	5.5			4.8			4.8
Interest Expense	54.4			55.7			61.8
Loss before Taxes	(56.8		)	(57.3		)	(63.9		)
Income Tax Benefit	26.4			26.0			30.8
Loss after Taxes	(30.4		)	(31.3		)	(33.1		)
Equity in Subsidiaries' Continuing Operations	607.8			577.6			545.9
Income from Continuing Operations	577.4			546.3			512.8
Income from Discontinued Operations including Equity in Subsidiaries' Discontinued Operations	—			—			13.4
Net Income	$	577.4		$	546.3		$	526.2
See accompanying notes to condensed parent company financial statements.

113 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

	Year Ended December 31
	2013			2012			2011
	(Millions of Dollars)
Operating Activities
Net income	$	577.4		$	546.3		$	526.2
Reconciliation to cash
Equity in subsidiaries' earnings	(607.8		)	(577.6		)	(545.9		)
Dividends and distributions from subsidiaries	720.4			842.3			995.5
Deferred income taxes, net	(7.8		)	104.4			(350.9		)
Accrued income taxes, net	66.8			(457.9		)	363.4
Change in - Other current assets	(0.1		)	0.2			(0.1		)
Change in - Other current liabilities	(22.9		)	(6.7		)	8.9
Change in - Accounts receivable	(2.7		)	22.5			(18.7		)
Other, net	(21.6		)	(8.1		)	(10.2		)
Cash Provided by Operating Activities	701.7			465.4			968.2
Investing Activities
Capital contributions to associated companies	(195.3		)	(21.5		)	(36.5		)
Capitalized interest and other	4.0			12.6			2.4
Cash Used in Investing Activities	(191.3		)	(8.9		)	(34.1		)
Financing Activities
Exercise of stock options	48.5			49.8			54.4
Purchase of common stock	(223.4		)	(153.9		)	(193.9		)
Dividends paid on common stock	(328.9		)	(276.3		)	(242.0		)
Retirement of long-term debt	—			—			(450.0		)
Change in short-term debt	5.0			(79.5		)	(116.5		)
Change in notes payable due associated companies	(26.8		)	3.8			3.9
Other, net	14.6			—			9.9
Cash Used in Financing Activities	(511.0		)	(456.1		)	(934.2		)
Change in Cash and Cash Equivalents	(0.6		)	0.4			(0.1		)
Cash and Cash Equivalents at Beginning of Year	0.9			0.5			0.6
Cash and Cash Equivalents at End of Year	$	0.3		$	0.9		$	0.5
See accompanying notes to condensed parent company financial statements.

114 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION

BALANCE SHEETS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

	December 31
	2013		2012
	(Millions of Dollars)
Assets
Current Assets
Cash and cash equivalents	$	0.3	$	0.9
Accounts and notes receivable from associated companies	37.4		32.9
Prepaid taxes and other	297.6		176.3
Total Current Assets	335.3		210.1
Property and Investments
Investment in subsidiary companies	4,761.8		4,662.3
Other	1.8		2.1
Total Property and Investments	4,763.6		4,664.4
Deferred Charges and Other Assets	143.2		331.4
Total Assets	$	5,242.1	$	5,205.9
Liabilities and Equity
Current Liabilities
Short-term debt	$	72.0	$	67.0
Notes payable due associated companies	113.8		140.6
Accrued taxes and other	11.8		34.7
Total Current Liabilities	197.6		242.3
Long-term debt	695.0		694.3
Other Long-term liabilities	116.5		134.2
Stockholder's equity	4,233.0		4,135.1
Total Liabilities and Equity	$	5,242.1	$	5,205.9
See accompanying notes to condensed parent company financial statements.

115 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

1.    For Parent Company only presentation, investment in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Wisconsin Energy Corporation appearing in this Annual Report on Form 10-K.

2.    Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from the Parent Company's non-utility subsidiary, We Power, and its principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. During 2013, Wisconsin Electric and Wisconsin Gas collectively provided Wisconsin Energy with $373.0 million of dividends, and We Power provided $347.4 million of distributions.

Various financing arrangements and regulatory requirements impose certain restrictions on the ability of the Parent Company's subsidiaries to transfer funds to the Parent Company in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to the Parent Company.

Wisconsin Energy does not believe that these restrictions will materially affect the Parent Company's operations or limit any dividend payments in the foreseeable future.

3.    As of December 31, 2013, the maturities of the Parent Company long-term debt outstanding were as follows:

	(Millions of Dollars)
2014	$	—
2015	—
2016	—
2017	—
2018	—
Thereafter	700.0
Total	$	700.0

Wisconsin Energy amortizes debt premiums, discounts and debt issuance costs over the lives of the debt and includes the costs in interest expense.

Wisconsin Energy entered into a new bank back-up credit facility in December 2012. The facility contains customary covenants, including certain limitations on Wisconsin Energy's 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, ERISA defaults and change of control. In addition, pursuant to the terms of the credit facility, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein. In addition, Wisconsin Energy is required to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%.

As of December 31, 2013, Wisconsin Energy was in compliance with all covenants.

WECC is a subsidiary of Wisconsin Energy and has $50 million of long-term notes outstanding. In a Support Agreement between WECC and Wisconsin Energy, Wisconsin Energy agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due.

4.    Wisconsin Energy and certain of its subsidiaries enter into various guarantees to provide financial and performance assurance to third parties on behalf of affiliates. As of December 31, 2013, Wisconsin Energy had the following

116 Wisconsin Energy Corporation

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS - (Cont'd) 2013 Form 10-K

guarantees which are eliminated upon consolidation and not included in the Wisconsin Energy Notes to Consolidated Statements:

	Maximum				Liability
	Potential		Outstanding		Recorded
	Future		as of		as of
	Payments		Dec 31, 2013		Dec 31, 2013
	(Millions of Dollars)
Wisconsin Energy Guarantees
Utility	$	3.8	$	3.8	$	—
Non-Utility Energy	55.5		—		—
Other	0.3		—		—
Total	$	59.6	$	3.8	$	—
Letters of Credit	$	0.1	$	0.1	$	—

Utility guarantees support obligations of the utility segment under surety bonds, worker's compensation and agreements.

Wisconsin Energy's guarantees in support of its non-utility energy segment guaranty performance and payment obligations of We Power. The guarantees which support We Power are for obligations under purchase, construction and lease agreements with the utility segment and third parties.

Wisconsin Energy has a guarantee that supports an environmental indemnification obligation, which is unlimited, associated with the Minergy Neenah plant and indemnifications related to the post-closing obligations under the Minergy Neenah sale agreement which was entered into in September 2006. In the event the guarantee fails to perform, Wisconsin Energy would be responsible for the obligations.

5.    The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2013				2012
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Long-term debt including current portion	$	700.0	$	749.4	$	700.0	$	805.9

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 long-term debt, including the current portion of long-term debt, 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 Parent Company's bond rating and the present value of future cash flows.

6.    During the year ended December 31, 2013, Wisconsin Energy paid $44.4 million in interest, net of amounts capitalized, and received $86.1 million in refunds from income taxes. During the year ended December 31, 2012, Wisconsin Energy paid $45.2 million in interest, net of amounts capitalized, and received $128.2 million in refunds from income taxes. During the year ended December 31, 2011, Wisconsin Energy paid $57.7 million in interest, net of amounts capitalized, and received $114.6 million in refunds from income taxes.

Subsequent Event: On January 16, 2014, Wisconsin Electric's board of directors declared a special dividend of $50.0 million which was paid to Wisconsin Energy on January 30, 2014.

117 Wisconsin Energy Corporation

2013 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, 2013	$	58.0	$	49.4	$	0.4		$	(46.8	)	$	61.0
December 31, 2012	$	61.7	$	47.7	$	(4.0	)	$	(47.4	)	$	58.0
December 31, 2011	$	58.1	$	85.8	$	(35.9	)	$	(46.3	)	$	61.7

118 Wisconsin Energy Corporation

2013 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 ENERGY CORPORATION
	By	/s/GALE E. KLAPPA
Date:	February 27, 2014	Gale E. Klappa, Chairman of the Board 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, 2014
Gale E. Klappa, Chairman of the Board, Chief Executive
Officer and Director -- Principal Executive Officer
/s/J. PATRICK KEYES	February 27, 2014
J. Patrick Keyes, Executive Vice President and Chief
Financial Officer -- Principal Financial Officer
/s/STEPHEN P. DICKSON	February 27, 2014
Stephen P. Dickson, Vice President and
Controller -- Principal Accounting Officer
/s/JOHN F. BERGSTROM	February 27, 2014
John F. Bergstrom, Director
/s/BARBARA L. BOWLES	February 27, 2014
Barbara L. Bowles, Director
/s/PATRICIA W. CHADWICK	February 27, 2014
Patricia W. Chadwick, Director
/s/CURT S. CULVER	February 27, 2014
Curt S. Culver, Director
/s/THOMAS J. FISCHER	February 27, 2014
Thomas J. Fischer, Director
/s/HENRY W. KNUEPPEL	February 27, 2014
Henry W. Knueppel, Director
/s/ULICE PAYNE, JR.	February 27, 2014
Ulice Payne, Jr., Director
/s/MARY ELLEN STANEK	February 27, 2014
Mary Ellen Stanek, Director

119 Wisconsin Energy Corporation

2013 Form 10-K

WISCONSIN ENERGY CORPORATION

(Commission File No. 001-09057)

EXHIBIT INDEX

to

Annual Report on Form 10-K

For the year ended December 31, 2013

The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Energy Corporation. (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 Energy Corporation, as amended effective May 21, 2012. (Exhibit3.1 to Wisconsin Energy Corporation's 06/30/12 Form10-Q.)
	3.2*	Bylaws of Wisconsin Energy Corporation, as amended to May 21, 2012. (Exhibit 3.2 to Wisconsin Energy Corporation's 06/30/12 Form10-Q.)
4	Instruments defining the rights of security holders, including indentures
	4.1*	Reference is made to ArticleIII of the Restated Articles of Incorporation and the Bylaws of Wisconsin Energy Corporation. (Exhibits3.1 and 3.2 herein.)
	4.2*	Replacement Capital Covenant, dated May 11, 2007, by Wisconsin Energy Corporation for the benefit of certain debtholders named therein. (Exhibit 4.2 to Wisconsin Energy Corporation's 05/08/07 Form 8-K.)
	Indentures and Securities Resolutions:
	4.3*	Indenture for Debt Securities of Wisconsin Electric Power Company (the "Wisconsin Electric Indenture"), dated December1, 1995. (Exhibit (4)-1 under File No.1-1245, Wisconsin Electric's 12/31/95 Form10-K.)
	4.4*	Securities Resolution No.1 of Wisconsin Electric under the Wisconsin Electric Indenture, dated December5, 1995. (Exhibit(4)-2 under File No.1-1245, Wisconsin Electric's 12/31/95 Form10-K.)
	4.5*	Securities Resolution No. 3 of Wisconsin Electric under the Wisconsin Electric Indenture, dated May 27, 1998. (Exhibit (4)-1 Under File No. 1-1245, Wisconsin Electric’s 06/30/98 Form 10-Q.)
	4.6*	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 FormS-3 (File No. 333-101054), filed May 6, 2003.)
	4.7*	Securities Resolution No. 7 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 2, 2006. (Exhibit 4.1 Under File No. 1-1245, Wisconsin Electric's 11/02/06 Form 8-K.)

E-1 Wisconsin Energy Corporation

2013 Form 10-K

Number	Exhibit
	4.8*	Securities Resolution No. 8 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of September 25, 2008. (Exhibit 4.1 Under File No. 1-1245, Wisconsin Electric's 09/25/08 Form 8-K.)
	4.9*	Securities Resolution No. 9 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2008. (Exhibit 4.1 Under File No. 1-1245, Wisconsin Electric's 12/08/08 Form 8-K.)
	4.10*	Securities Resolution No. 10 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2009. (Exhibit 4.1 Under File No. 1-1245, Wisconsin Electric's 12/08/09 Form 8-K.)
	4.11*	Securities Resolution No. 11 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of September 7, 2011. (Exhibit 4.1 Under File No. 1-1245, Wisconsin Electric's 09/07/11 Form 8-K.)
	4.12*	Securities Resolution No. 12 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 5, 2012. (Exhibit 4.1 Under File No. 1-1245, Wisconsin Electric's 12/05/12 Form 8-K.)
	4.13*	Securities Resolution No. 13 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of June 10, 2013. (Exhibit 4.1 Under File No. 1-1245, Wisconsin Electric's 06/10/13 Form 8-K.)
	4.14*	Indenture for Debt Securities of Wisconsin Energy Corporation (the "Wisconsin Energy Indenture"), dated as of March15, 1999. (Exhibit4.46 to Wisconsin Energy Corporation's 03/25/99 Form8-K.)
	4.15*	Securities Resolution No.4 of Wisconsin Energy under the Wisconsin Energy Indenture, dated as of March17, 2003. (Exhibit 4.12 filed with Post-Effective Amendment No. 1 to Wisconsin Energy Corporation's Registration Statement on FormS-3 (File No. 333-69592), filed March 20, 2003.)
	4.16*	Securities Resolution No. 5 of Wisconsin Energy under the Wisconsin Energy Indenture, dated as of May 8, 2007. (Exhibit 4.1 to Wisconsin Energy Corporation's 05/08/07 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 subsidiaries 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, effective as of January 1, 2005. (Exhibit 10.9 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** 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.)

E-2 Wisconsin Energy Corporation

2013 Form 10-K

Number	Exhibit
	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 Form10-K.)
	10.4*	Executive Deferred Compensation Plan of Wisconsin Energy Corporation, as amended and restated as of July23, 2004 (including amendments approved effective as of November2, 2005) (the "Legacy EDCP"). (Exhibit 10.2 to Wisconsin Energy Corporation's 09/30/05 Form10-Q.)** See Note.
	10.5*	First Amendment to the Legacy EDCP, effective as of January 1, 2005. (Exhibit 10.12 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.6*	Wisconsin Energy Corporation Executive Deferred Compensation Plan, amended and restated effective as of September 8, 2009. (Exhibit 10.9 to Wisconsin Energy Corporation's 12/31/11 Form 10-K.)** See Note.
	10.7*	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 Form10-Q.)** See Note.
	10.8*	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.)** See Note.
	10.9	Wisconsin Energy Corporation Directors' Deferred Compensation Plan, effective as of January 1, 2005. (Exhibit 10.16 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** 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.) ** 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 Form8-K.)** 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.)** See Note.
	10.13*	Restated Non-Qualified Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 11, 2004 (the “Non-Qualified Trust Agreement”), regarding trust established to provide a source of funds to assist in meeting of the liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.16 to Wisconsin Energy Corporation's 12/31/07 Form 10-K.)** See Note.
	10.14*	First Amendment to the Non-Qualified Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company, effective as of July 23, 2013. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/13 Form 10-Q.)** See Note.
	10.15*	Affiliated Interest Agreement (Service Agreement), dated December12, 2002, by and among Wisconsin Energy Corporation and its affiliates. (Exhibit 10.14 to Wisconsin Energy Corporation's 12/31/02 Form10-K.)

E-3 Wisconsin Energy Corporation

2013 Form 10-K

Number	Exhibit
	10.16*	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.)** See Note.
	10.17*	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.)** See Note.
	10.18*	Consulting Agreement between Wisconsin Energy Corporation and Frederick D. Kuester, dated as of January 7, 2013. (Exhibit 10.18 to Wisconsin Energy Corporation's 12/31/12 Form 10-K.)** See Note.
	10.19*	Terms of Employment for J. Patrick Keyes. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/12 Form 10-Q.)** See Note.
	10.20*	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.)** See Note.
	10.21*	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.)** See Note
	10.22*	Terms of Employment for Susan H. Martin. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/12 Form 10-Q.)** See Note.
	10.23*	Amended and Restated Senior Officer, Change in Control, Severance and Non-Compete Agreement between Wisconsin Energy Corporation and Kristine A. Rappé, dated as of December 30, 2008. (Exhibit 10.30 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.24*	Separation Agreement and General Release between Wisconsin Energy Corporation and Kristine A. Rappé, effective December 28, 2012 (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/12 Form 10-K.)** See Note.
	10.25*	Supplemental Pension Benefit Agreement between Wisconsin Energy Corporation and Stephen Dickson, effective May23, 2001. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/01 Form10-Q.)** See Note.
	10.26*	Amendment to the Supplemental Pension Benefit Agreement between Wisconsin Energy Corporation and Stephen Dickson, dated December 29, 2008. (Exhibit 10.32 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.27*	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.)** See Note.
	10.28*	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.)** See Note.

E-4 Wisconsin Energy Corporation

2013 Form 10-K

Number	Exhibit
	10.29*	Letter Agreement by and 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.)** See Note.
	10.30*	1993 Omnibus Stock Incentive Plan, amended and restated effective as of May 5, 2011, as approved by the stockholders at the 2011 annual meeting of stockholders. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/11 Form 10-Q.)** See Note.
	10.31*	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 Form8-K.)** See Note.
	10.32*	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.)** See Note.
	10.33*	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.)** See Note.
	10.34*	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.)** See Note.
	10.35*	Wisconsin Energy Corporation Performance Unit Plan, amended and restated effective as of January 1, 2010. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/03/09 Form 8-K.)** See Note.
	10.36*	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 Form8-K.)** See Note.
	10.37*	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 Power Company's 06/30/03 Form10-Q (File No. 001-01245).)
	10.38*	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 Power Company's 06/30/03 Form10-Q (File No. 001-01245).)
	10.39*	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 Form10-K.)
	10.40*	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 Form10-K.)

E-5 Wisconsin Energy Corporation

2013 Form 10-K

Number	Exhibit
	10.41*	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.)
	10.42*	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.)
	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 Energy Corporation.
23	Consents of experts and counsel
	23.1	Deloitte & Touche LLP -- Milwaukee, WI, Consent of Independent Registered Public Accounting Firm.
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 Energy Corporation

EX-21.1

Exhibit 21.1

WISCONSIN ENERGY CORPORATION

SUBSIDIARIES AS OF DECEMBER 31, 2013

The following table includes the subsidiaries of Wisconsin Energy Corporation, a diversified holding company incorporated in the state of Wisconsin, as well as the percent of ownership, as of December 31, 2013:

	State of
	Incorporation	Percent
Subsidiary (a)	or Organization	Ownership
Wisconsin Electric Power Company	Wisconsin	100%
ATC Management Inc.	Wisconsin	26.24%
American Transmission Company LLC	Wisconsin	23.04%
Bostco LLC	Wisconsin	100%
Wisconsin Gas LLC	Wisconsin	100%
ATC Holding LLC	Wisconsin	100%
American Transmission Company LLC	Wisconsin	3.20%
W.E. Power, LLC	Wisconsin	100%
Elm Road Generating Station Supercritical, LLC	Wisconsin	100%
Elm Road Services, LLC	Wisconsin	100%
Port Washington Generating Station, LLC	Wisconsin	100%
Wisvest LLC	Wisconsin	100%
Wispark LLC	Wisconsin	100%
CenterPoint Wispark Land Company LLC	Wisconsin	32.95%
2825 Four Mile Road LLC	Wisconsin	100%
Wisconsin Energy Capital Corporation	Wisconsin	100%

(a) Omits the names of certain subsidiaries, which if considered in the aggregate as a single subsidiary, would not constitute a "significant subsidiary" as of December 31, 2013. Indirectly owned subsidiaries are listed under the subsidiaries through which Wisconsin Energy Corporation holds ownership.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-177575 on Form S-3 and Registration Statement Nos. 333-161151 and 333-177572 on Form S-8 of our reports dated February 27, 2014, relating to the consolidated financial statements and financial statement schedules of Wisconsin Energy Corporation and subsidiaries (the “Company”), and the effectiveness of the Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of the Company for the year ended December 31, 2013.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 27, 2014

EX-31.1

Exhibit 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

I, Gale E. Klappa, certify that:

1. I have reviewed this annual report on Form 10-K of Wisconsin Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2014

/s/GALE E. KLAPPA

Gale E. Klappa

Chairman and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 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

I, J. Patrick Keyes, certify that:

1. I have reviewed this annual report on Form 10-K of Wisconsin Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2014

/s/J. PATRICK KEYES

J. Patrick Keyes

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Wisconsin Energy Corporation (the "Company") on Form 10-K for the period ended December 31, 2013, as filed with the Securities and Exchange Commission on February 27, 2014 (the "Report"), I, Gale E. Klappa, Chairman and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/GALE E. KLAPPA 

Gale E. Klappa

Chairman and Chief Executive Officer

February 27, 2014

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Wisconsin Energy Corporation (the "Company") on Form 10-K for the period ended December 31, 2013, as filed with the Securities and Exchange Commission on February 27, 2014 (the "Report"), I, J. Patrick Keyes, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/J. PATRICK KEYES

J. Patrick Keyes

Executive Vice President and Chief Financial Officer

February 27, 2014

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments (Tables) [Abstract]

Derivative instruments in balance sheet

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 $0.4 million is recorded in other deferred charges and other assets, and we had no long-term portion of derivative liabilities. Our Consolidated Balance Sheets as of December 31, 2013 and 2012 include:

	December 31, 2013				December 31, 2012
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	5.6	$	0.1	$	3.0	$	1.9
Fuel Oil	0.6		—		0.4		—
FTRs	3.5		—		4.7		—
Coal	2.1		0.2		11.1		—
Total	$	11.8	$	0.3	$	19.2	$	1.9

Derivative instruments' estimated notional volumes and gain (losses)

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 were as follows:

	2013				2012
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	48.6 million Dth	$	(8.5	)	77.2 million Dth	$	(36.3	)
Fuel Oil	8.6 million gallons	0.5			7.0 million gallons	1.8
FTRs	25.3 million MWh	14.9			25.1 million MWh	6.1
Total		$	6.9			$	(28.4	)

Offsetting Assets and Liabilities [Table Text Block]

	2013				2012
	Derivative		Derivative		Derivative			Derivative
	Asset		Liability		Asset			Liability
	(Millions of Dollars)
Gross Amount Recognized on the Balance Sheet	$	11.8	$	0.3	$	19.2		$	1.9
Gross Amount Not Offset on Balance Sheet (a)	—		—		(0.5		)	(1.8		)
Net Amount	$	11.8	$	0.3	$	18.7		$	0.1

(a) Gross Amount Not Offset on Balance Sheet includes cash collateral posted of zero and $1.3 million as of December 31, 2013 and 2012, respectively.

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 Megawatt	Dec. 31, 2012	Dec. 31, 2011
Variable Interest Entities (Textuals)
Power capacity from a gas-fired cogeneration facility under capital lease (MW)	236
Capital lease agreement with VIE remaining term in years	9 years
Total payments over remaining terms of the two agreements	$ 215.9
Total capacity and minimum lease payments	$ 50.3	$ 45.8	$ 65.9

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Summary of Significant Accounting Policies (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property in Service by Segment
Property In Service	$ 14,966.3	$ 14,238.8
Construction Work in Progress (CWIP) by segment
Construction Work in Progress (CWIP)	149.6	315.9
Goodwill related to acquisition of Wisconsin Gas	441.9	441.9
Utility Energy [Member]
Property in Service by Segment
Property In Service	11,779.8	11,080.9
Construction Work in Progress (CWIP) by segment
Construction Work in Progress (CWIP)	132.7	298.2
Non-Utility Energy [Member]
Property in Service by Segment
Property In Service	3,091.3	3,068.5
Construction Work in Progress (CWIP) by segment
Construction Work in Progress (CWIP)	16.5	13.3
Corporate and Other [Member]
Property in Service by Segment
Property In Service	95.2	89.4
Construction Work in Progress (CWIP) by segment
Construction Work in Progress (CWIP)	$ 0.4	$ 4.4

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Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans [Member]
Change in Benefit Obligation
Benefit Obligation at January 1	$ 1,508.5	$ 1,330.6
Service cost	14.6	21.7	15.9
Interest cost	60.4	65.5	67.6
Participants' contributions	0	0
Plan amendments	(1.0)	0
Actuarial loss (gain)	(81.9)	166.5
Curtailments	0	31.4
Gross benefits paid	(90.4)	(107.2)
Benefit Obligation at December 31	1,410.2	1,508.5	1,330.6
OPEB [Member]
Change in Benefit Obligation
Benefit Obligation at January 1	381.2	389.7
Service cost	10.0	10.3	10.4
Interest cost	15.6	20.3	20.8
Participants' contributions	8.9	9.6
Plan amendments	0	0.5
Actuarial loss (gain)	(27.7)	(23.8)
Curtailments	0	0
Gross benefits paid	(26.3)	(26.3)
Federal subsidy on benefits paid	1.0	0.9
Benefit Obligation at December 31	$ 362.7	$ 381.2	$ 389.7

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of income tax expense
Current tax expense (benefit)	$ 25.2	$ 13.1	$ (166.7)
Deferred income taxes, net	313.8	294.4	434.8
Investment tax credit, net	(1.1)	(1.2)	(4.2)
Total Income Tax Expense, Amount	337.9	306.3	263.9
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 as a result of the following:
Expected tax at statutory federal tax rates, Amount	320.3	298.4	271.8
Expected tax at statutory federal tax rates, Effective Tax Rate	35.00%	35.00%	35.00%
State income taxes net of federal tax benefit, Amount	49.0	43.3	40.1
State income taxes net of federal tax benefit, Effective Tax Rate	5.30%	5.10%	5.20%
Domestic production activities deduction, Amount	0	(12.6)	(12.6)
Domestic production activities deduction, Effective Tax Rate	0.00%	(1.50%)	(1.60%)
AFUDC - Equity, Amount	(6.4)	(12.3)	(20.8)
AFUDC - Equity, Effective Tax Rate	(0.70%)	(1.40%)	(2.70%)
Production tax credits - wind, Amount	(16.7)	(15.9)	(8.7)
Production tax credits - wind, Effective Tax Rate	(1.80%)	(1.90%)	(1.10%)
Effective Tax Rate Reconciliation, 1603 Grant, Amount	(7.4)	0	0
Effective Tax Rate Reconciliation, 1603 Grant, Percent	(0.80%)	0.00%	0.00%
Investment tax credit restored, Amount	(1.1)	(1.2)	(4.2)
Investment tax credit restored, Effective Tax Rate	(0.10%)	(0.10%)	(0.50%)
Other, net, Amount	0.2	6.6	(1.7)
Other, net, Effective Tax Rate	0.00%	0.70%	(0.30%)
Total Income Tax Expense, Amount	337.9	306.3	263.9
Total Income Tax Expense, Effective Tax Rate	36.90%	35.90%	34.00%
Current
Deferred Tax Assets, Future Federal Tax Benefits, Current	309.7	59.0
Employee benefits and compensation	13.8	14.9
Other	56.0	81.1
Total Current Deferred Tax Assets	379.5	155.0
Non-current
Deferred revenues	237.0	250.0
Employee benefits and compensation	95.6	97.0
Deferred Tax Assets, Future Federal Tax Benefits, Non Current	32.5	334.7
Property-related	28.2	28.3
Construction advances	18.3	22.2
Other	62.9	16.3
Total Non-current Deferred Tax Assets	474.5	748.5
Total Deferred Tax Assets	854.0	903.5
Current
Prepaid items	69.5	49.7
Total Current Deferred Tax Liabilities	69.5	49.7
Non-current
Property-related	2,574.4	2,339.4
Employee benefits and compensation	238.5	244.3
Investment in transmission affiliate	169.9	144.9
Deferred transmission costs	50.8	45.7
Other	74.9	91.2
Total Non-current Deferred Tax Liabilities	3,108.5	2,865.5
Total Deferred Tax Liabilities	3,178.0	2,915.2
Consolidated Balance Sheet Presentation
Current Deferred Tax Asset	310.0	105.3
Non-Current Deferred Tax Liability	2,634.0	2,117.0
Reconciliation of the beginning and ending amount of unrecognized tax benefits
Balance, January 1	11.3	11.1
Additions for tax positions of prior years	0	10.8
Reductions for tax positions of prior years	(2.9)	(10.6)
Balance, December 31	8.4	11.3	11.1
Income Taxes (Textuals)
Deferred tax assets valuation allowance	8.4	10.2
Net amount of unrecognized tax benefits having impact on the effective tax rate for continuing operations	0	1.0
Accrued interest in the Consolidated Income Statements	0.2	0.2	0.7
Accrued penalties in the Consolidated Income Statements	0	0	0.3
Accrued interest on the Consolidated Balance Sheets	0.4	0.3
Accrued penalties on the Consolidated Balance Sheets	0	0
Operating Loss Carryforwards	810.3	1,007.1
Deferred Tax Assets, Operating Loss Carryforwards	283.6	352.5
Tax Credit Carryforward, Amount	58.6	41.2
Tax Credit Carryforward, Deferred Tax Asset	$ 58.6	$ 41.2

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Condensed Parent Company Financial Statements (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 26.0		$ 35.6		$ 14.1		$ 24.5
Prepaid taxes and other	145.7		145.5
Total Current Assets	1,551.1		1,272.6
Property and Investments
Investment in subsidiary companies	402.7		378.3
Other	322.5		204.2
Total Deferred Charges and Other Assets	1,872.9		2,026.4
Total Assets	14,769.4	[1]	14,285.0	[1]	13,862.1	[1]
Current Liabilities
Short-term debt	537.4		394.6
Other	177.3		165.4
Total Current Liabilities	1,496.4		1,441.4
Long-term debt	4,363.2		4,453.8
Other Long-term liabilities	295.9		285.2
Stockholder's equity	4,233.0		4,135.1		3,963.3		3,802.1
Total Capitalization and Liabilities	14,769.4		14,285.0
Wisconsin Energy Corporation [Member]
Current Assets
Cash and cash equivalents	0.3		0.9		0.5		0.6
Accounts and notes receivable from associated companies	37.4		32.9
Prepaid taxes and other	297.6		176.3
Total Current Assets	335.3		210.1
Property and Investments
Investment in subsidiary companies	4,761.8		4,662.3
Other	1.8		2.1
Total Property and Investments	4,763.6		4,664.4
Total Deferred Charges and Other Assets	143.2		331.4
Total Assets	5,242.1		5,205.9
Current Liabilities
Short-term debt	72.0		67.0
Notes payable due associated companies	113.8		140.6
Other	11.8		34.7
Total Current Liabilities	197.6		242.3
Long-term debt	695.0		694.3
Other Long-term liabilities	116.5		134.2
Stockholder's equity	4,233.0		4,135.1
Total Capitalization and Liabilities	$ 5,242.1		$ 5,205.9

[1] An elimination of $2,231.2 million, $2,286.7 million and $2,369.0 million is included in Total Assets as of December 31, 2013, 2012 and 2011, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

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Summary Of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Public Utility Property Plant And Equipment [Line Items]
Public Utilities, Disclosure of Rate Matters	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.
Goodwill	$ 441.9	$ 441.9
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service	2.90%	2.90%	2.80%
Regulatory liabilities	879.1	868.3
Equity Method Investment, Ownership Percentage	50.00%
PWGS 1 [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciation over an estimated useful life	10 to 45 years
PWGS 2 [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciation over an estimated useful life	10 to 45 years
OC 1 [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciation over an estimated useful life	10 to 55 years
OC 2 [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciation over an estimated useful life	10 to 55 years
Asset Retirement Obligation Costs [Member]
Public Utility Property Plant And Equipment [Line Items]
Regulatory liabilities	$ 724.5	$ 725.0
Transmission Affiliate [Member]
Public Utility Property Plant And Equipment [Line Items]
Equity Method Investment, Ownership Percentage		26.20%
Maximum [Member]
Public Utility Property Plant And Equipment [Line Items]
Risk-free interest rate	1.90%	2.00%	3.40%
Minimum [Member]
Public Utility Property Plant And Equipment [Line Items]
Risk-free interest rate	0.10%	0.10%	0.20%

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Asset Sales, Divestitures And Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Sales, Divestitures And Discontinued Operations (Tables) [Abstract]

Net impacts of the discontinued operations on earnings

The following table summarizes the net impacts of the discontinued operations on our earnings for the years ended December 31:

	2013		2012		2011
	(Millions of Dollars)
Income from Continuing Operations	$	577.4	$	546.3	$	512.8
Income from Discontinued other operations, net of tax (a)	—		—		13.4
Net Income	$	577.4	$	546.3	$	526.2

(a) Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

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Condensed Parent Company Financial Statements (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities
Net income	$ 577.4	$ 546.3	$ 526.2
Reconciliation to cash
Deferred income taxes, net	313.8	294.4	434.8
Accrued income taxes, net	36.6	116.9	(87.4)
Other current assets	2.8	12.1	(20.5)
Other current liabilities	7.2	(14.9)	44.1
Accounts receivable and accrued revenues	(162.9)	38.3	30.1
Other, net	49.2	(164.0)	(23.5)
Cash Provided by Operating Activities	1,231.0	1,173.9	993.4
Investing Activities
Proceeds from asset sales	2.5	8.7	41.5
Capital contributions to associated companies	(10.5)	(15.7)	(6.6)
Cash Used in Investing Activities	(745.8)	(729.6)	(892.5)
Financing Activities
Exercise of stock options	48.5	49.8	54.4
Purchase of common stock	(223.4)	(153.2)	(193.9)
Dividends paid on common stock	(328.9)	(276.3)	(242.0)
Issuance of long-term debt	251.0	251.8	720.0
Retirement and repurchase of long-term debt	(397.2)	(20.3)	(466.6)
Change in short-term debt	142.8	(275.3)	12.0
Other, net	12.4	0.7	4.8
Cash Used in Financing Activities	(494.8)	(422.8)	(111.3)
Change in Cash and Cash Equivalents	(9.6)	21.5	(10.4)
Cash and Cash Equivalents at Beginning of Year	35.6	14.1	24.5
Cash and Cash Equivalents at End of Year	26.0	35.6	14.1
Wisconsin Energy Corporation [Member]
Operating Activities
Net income	577.4	546.3	526.2
Reconciliation to cash
Equity in susidiaries' earnings	(607.8)	(577.6)	(545.9)
Dividends and distributions from subsidiaries	720.4	842.3	995.5
Deferred income taxes, net	(7.8)	104.4	(350.9)
Accrued income taxes, net	66.8	(457.9)	363.4
Other current assets	(0.1)	0.2	(0.1)
Other current liabilities	(22.9)	(6.7)	8.9
Accounts receivable and accrued revenues	(2.7)	22.5	(18.7)
Other, net	(21.6)	(8.1)	(10.2)
Cash Provided by Operating Activities	701.7	465.4	968.2
Investing Activities
Capital contributions to associated companies	(195.3)	(21.5)	(36.5)
Capitalized interest and other	4.0	12.6	2.4
Cash Used in Investing Activities	(191.3)	(8.9)	(34.1)
Financing Activities
Exercise of stock options	48.5	49.8	54.4
Purchase of common stock	(223.4)	(153.9)	(193.9)
Dividends paid on common stock	(328.9)	(276.3)	(242.0)
Retirement and repurchase of long-term debt	0	0	(450.0)
Change in short-term debt	5.0	(79.5)	(116.5)
Change in notes payable due associated companies	(26.8)	3.8	3.9
Other, net	14.6	0	9.9
Cash Used in Financing Activities	(511.0)	(456.1)	(934.2)
Change in Cash and Cash Equivalents	(0.6)	0.4	(0.1)
Cash and Cash Equivalents at Beginning of Year	0.9	0.5	0.6
Cash and Cash Equivalents at End of Year	$ 0.3	$ 0.9	$ 0.5

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Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Financial information of reportable operating segments
Operating Revenues	$ 4,519.0	[1]	$ 4,246.4	[1]	$ 4,486.4	[1]
Depreciation and Amortization	388.1		364.2		330.2
Operating Income (Loss)	1,080.1		1,000.3		887.3
Equity in Earnings of Unconsolidated Affiliates	68.4		65.5		61.6
Interest Expense, net	252.1		248.2		235.8
Income Tax Expense (Benefit)	337.9		306.3		263.9
Income from Discontinued Operations, Net of Tax	0		0		13.4
Net Income (Loss)	577.4		546.3		526.2
Capital Expenditures	687.4		707.0		830.8
Total Assets	(14,769.4)	[2]	(14,285.0)	[2]	(13,862.1)	[2]
Utility Energy [Member]
Financial information of reportable operating segments
Operating Revenues	4,462.0	[1]	4,190.8	[1]	4,431.5	[1]
Depreciation and Amortization	320.2		296.4		257.0
Operating Income (Loss)	719.4		647.7		544.8
Equity in Earnings of Unconsolidated Affiliates	68.5		65.7		62.5
Interest Expense, net	136.2		129.4		110.0
Income Tax Expense (Benefit)	243.6		214.9		182.7
Income from Discontinued Operations, Net of Tax					0
Net Income (Loss)	425.1		400.6		376.3
Capital Expenditures	657.9		697.3		792.2
Total Assets	(14,460.4)	[2]	(13,988.1)	[2]	(13,433.5)	[2]
Non-Utility Energy [Member]
Financial information of reportable operating segments
Operating Revenues	446.7	[1]	439.9	[1]	435.1	[1]
Depreciation and Amortization	67.1		67.1		72.5
Operating Income (Loss)	367.1		358.8		348.9
Equity in Earnings of Unconsolidated Affiliates	0		0		0
Interest Expense, net	65.7		66.7		66.7
Income Tax Expense (Benefit)	120.2		116.6		112.8
Income from Discontinued Operations, Net of Tax					0
Net Income (Loss)	181.6		175.9		169.8
Capital Expenditures	26.1		5.5		31.2
Total Assets	(2,846.5)	[2]	(2,903.5)	[2]	(2,949.0)	[2]
Corporate and Other [Member]
Financial information of reportable operating segments
Operating Revenues	1.3	[1],[3]	1.2	[1],[3]	0.9	[1],[3]
Depreciation and Amortization	0.8	[3]	0.7	[3]	0.7	[3]
Operating Income (Loss)	(6.4)	[3]	(6.2)	[3]	(6.4)	[3]
Equity in Earnings of Unconsolidated Affiliates	(0.1)	[3]	(0.2)	[3]	(0.9)	[3]
Interest Expense, net	50.8	[3]	52.5	[3]	59.5	[3]
Income Tax Expense (Benefit)	(25.9)	[3]	(25.2)	[3]	(31.6)	[3]
Income from Discontinued Operations, Net of Tax					13.4	[3]
Net Income (Loss)	577.2	[3]	546.1	[3]	525.9	[3]
Capital Expenditures	3.4	[3]	4.2	[3]	7.4	[3]
Total Assets	(4,719.5)	[2],[3]	(4,431.4)	[2],[3]	(4,694.8)	[2],[3]
Reconciling Items [Member]
Financial information of reportable operating segments
Operating Revenues	(391.0)	[1]	(385.5)	[1]	(381.1)	[1]
Depreciation and Amortization	0		0		0
Operating Income (Loss)	0		0		0
Equity in Earnings of Unconsolidated Affiliates	0		0		0
Interest Expense, net	(0.6)		(0.4)		(0.4)
Income Tax Expense (Benefit)	0		0		0
Income from Discontinued Operations, Net of Tax					0
Net Income (Loss)	(606.5)		(576.3)		(545.8)
Capital Expenditures	0		0		0
Total Assets	7,257.0	[2]	7,038.0	[2]	7,215.2	[2]
Elimination [Member]
Financial information of reportable operating segments
Total Assets	$ 2,231.2		$ 2,286.7		$ 2,369.0

[1] An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

[2] An elimination of $2,231.2 million, $2,286.7 million and $2,369.0 million is included in Total Assets as of December 31, 2013, 2012 and 2011, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

[3] Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.

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Common Equity (Details 1) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended	12 Months Ended
	Jan. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock option activity
Outstanding, Shares, Beginning Balance	8,089,710
Outstanding, Weighted-Average Exercise Price, Beginning	$ 26.84
Granted, shares	899,500
Granted, Weighted-Average Exercise Price		$ 3.45	$ 3.34	$ 3.17
Outstanding, Shares, Ending Balance		8,089,710
Outstanding, Weighted-Average Exercise Price, Ending		$ 26.84
Exercisable, shares		5,708,920
Exercisable, Weighted-Average Exercise Price		$ 23.16
Stock Options [Member]
Stock option activity
Outstanding, Shares, Beginning Balance		8,919,669
Outstanding, Weighted-Average Exercise Price, Beginning		$ 23.86
Granted, Weighted-Average Exercise Price		$ 37.46
Exercised, shares		(2,238,489)
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price		$ 21.67
Forfeited, shares		(10,030)
Forfeited, Weighted-Average Exercise Price		$ 35.37
Outstanding, Shares, Ending Balance		8,089,710
Outstanding, Weighted-Average Exercise Price, Ending		$ 26.84
Outstanding, Weighted-Average Remaining Contractual Life (Years)		5 years 5 months
Outstanding, Aggregate Intrinsic Value		$ 117.3
Exercisable, shares		5,708,920
Exercisable, Weighted-Average Exercise Price		$ 23.16
Exercisable, Weighted-Average Remaining Contractual Life (Years)		4 years 1 month
Exercisable, Aggregate Intrinsic Value		$ 103.8

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Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Information (Textuals)
Interest paid, net of amounts capitalized	$ 250.4	$ 241.2	$ 234.0
Net refunds from income taxes	39.6	107.0	109.1
Accounts payable related to capital expenditures	4.7	15.7	16.7
Deferred Revenue, Revenue Recognized	56.5	54.9	54.4
Grants Receivable, Current	82.6
Revenue from Grants	$ 48.0	$ 0	$ 0

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Preferred Stock (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Preferred Stock, Value, Issued	$ 30.4	$ 30.4
Six Per Cent. Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	45,000
Preferred Stock, Shares Outstanding	44,498
Preferred Stock, Redemption Price Per Share	$ 0
Preferred Stock, Value, Issued	4.4
Serial preferred stock, $100 par value; authorized 2,286,500 shares [Member] [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	2,286,500
Serial preferred stock, 3.60% Series Redeemable [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	260,000
Preferred Stock, Redemption Price Per Share	$ 101
Preferred Stock, Value, Issued	26.0
Serial preferred stock, $25 par value; authorized 5,000,000 shares; none outstanding [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	5,000,000
Preferred Stock, Shares Outstanding	0
Preferred Stock, Redemption Price Per Share	$ 0
Preferred Stock, Value, Issued	0
Wisconsin Electric [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Issued	30.4	30.4
Wisconsin Electric [Member] | Six Per Cent. Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized		45,000
Preferred Stock, Dividend Rate, Percentage	6.00%	6.00%
Preferred Stock, Par or Stated Value Per Share	$ 100.00	$ 100.00
Preferred Stock, Shares Outstanding		44,498
Preferred Stock, Redemption Price Per Share		$ 0
Preferred Stock, Value, Issued		4.4
Wisconsin Electric [Member] | Serial preferred stock, $100 par value; authorized 2,286,500 shares [Member] [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized		2,286,500
Preferred Stock, Par or Stated Value Per Share	$ 100.00	$ 100.00
Wisconsin Electric [Member] | Serial preferred stock, 3.60% Series Redeemable [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	3.60%	3.60%
Preferred Stock, Par or Stated Value Per Share	$ 100.00	$ 100.00
Preferred Stock, Shares Outstanding		260,000
Preferred Stock, Redemption Price Per Share		$ 101
Preferred Stock, Value, Issued		26.0
Wisconsin Electric [Member] | Serial preferred stock, $25 par value; authorized 5,000,000 shares; none outstanding [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized		5,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0	$ 0
Preferred Stock, Shares Outstanding		0
Preferred Stock, Redemption Price Per Share		$ 0
Preferred Stock, Value, Issued		0
Wisconsin Energy Corporation [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	15,000,000	15,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Redemption Price Per Share	$ 0	$ 0
Preferred Stock, Value, Issued	$ 0	$ 0

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Condensed Parent Company Financial Statements (Details 4) (Wisconsin Energy Corporation [Member], USD $)	Dec. 31, 2013
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	$ 59,600,000
Guarantees, Outstanding	3,800,000
Liability	0
Letters of Credit [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	100,000
Guarantees, Outstanding	100,000
Liability	0
Utility Energy [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	3,800,000
Guarantees, Outstanding	3,800,000
Liability	0
Non-Utility Energy [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	55,500,000
Guarantees, Outstanding	0
Liability	0
Corporate and Other [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	300,000
Guarantees, Outstanding	0
Liability	$ 0

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Condensed Parent Company Financial Statements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Parent Company Income Statement
Other Income, Net	$ 18.8	$ 34.8	$ 62.7
Interest Expense, net	252.1	248.2	235.8
Income (Loss) from Continuing Operations Before Income Taxes	915.3	852.6	776.7
Income Tax Benefit	(337.9)	(306.3)	(263.9)
Income from Continuing Operations	577.4	546.3	512.8
Income from Discontinued Operations, Net of Tax	0	0	13.4
Net Income	577.4	546.3	526.2
Subsidiaries [Member]
Condensed Parent Company Income Statement
Income from Continuing Operations	607.8	577.6	545.9
Income from Discontinued Operations, Net of Tax	0	0	13.4
Wisconsin Energy Corporation [Member]
Condensed Parent Company Income Statement
Other Income, Net	3.1	3.2	2.7
Corporate Expense	5.5	4.8	4.8
Interest Expense, net	54.4	55.7	61.8
Income (Loss) from Continuing Operations Before Income Taxes	(56.8)	(57.3)	(63.9)
Income Tax Benefit	26.4	26.0	30.8
Income from Continuing Operations	(30.4)	(31.3)	(33.1)
Net Income	$ 577.4	$ 546.3	$ 526.2

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Benefits (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amounts recognized in Consolidated Balance Sheets
Other long-term liabilities	$ 173,200,000	$ 244,000,000
Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	1,409,500,000	1,507,100,000
Defined Benefit Plan, Benefit Obligation	1,410,200,000	1,508,500,000	1,330,600,000
Change in Plan Assets
Fair Value at January 1	1,385,400,000	1,262,500,000
Actual earnings (loss) on plan assets	147,300,000	127,400,000
Employer contributions	8,700,000	102,700,000
Participants' contributions	0	0
Gross benefits paid	(90,400,000)	(107,200,000)
Fair Value at December 31	1,451,000,000	1,385,400,000
Amounts recognized in Consolidated Balance Sheets
Other deferred charges	138,700,000	0
Other long-term liabilities	97,900,000	123,100,000
Net Liability	40,800,000	(123,100,000)
Amounts not yet been recognized in net periodic benefit cost
Net actuarial loss	528,800,000	719,200,000
Prior service costs (credits)	8,800,000	12,200,000
Total	537,600,000	731,400,000
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	362,700,000	381,200,000	389,700,000
Change in Plan Assets
Fair Value at January 1	285,400,000	255,400,000
Actual earnings (loss) on plan assets	45,500,000	29,000,000
Employer contributions	14,100,000	17,700,000	48,400,000
Participants' contributions	8,900,000	9,600,000
Gross benefits paid	(26,300,000)	(26,300,000)
Fair Value at December 31	327,600,000	285,400,000	255,400,000
Amounts recognized in Consolidated Balance Sheets
Other deferred charges	40,200,000	25,100,000
Other long-term liabilities	75,300,000	120,900,000
Net Liability	(35,100,000)	(95,800,000)
Amounts not yet been recognized in net periodic benefit cost
Net actuarial loss	9,800,000	65,300,000
Prior service costs (credits)	(1,700,000)	(3,700,000)
Total	$ 8,100,000	$ 61,600,000

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

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)
2014	$	3.9
2015	3.9
2016	3.7
2017	3.1
2018	3.2
Thereafter	22.7
Total	$	40.5

Divested Assets:   Pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to WPL 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 manufactured gas plant sites and related disposal sites used by Wisconsin Electric and Wisconsin Gas, and coal combustion product disposal/landfill sites used by Wisconsin Electric, as discussed below. 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 Wisconsin Electric, Wisconsin Gas, 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 $19 million to $56 millionover 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, 2013 and 2012, we established reserves of $36.9 million and $38.2 million, respectively, related to future remediation costs.

Historically, the PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, 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:   Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its 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 Wisconsin Electric has 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 2013, 2012 and 2011, Wisconsin Electric incurred $0.1 million, $0.3 million and $0.2 million respectively, in landfill remediation expenses. As of December 31, 2013, 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. Sierra Club and Clean Wisconsin requested and were granted an administrative hearing before the WDNR on certain conditions of the permit; however, the case has been stayed. In addition, 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 either proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

In August 2012, we announced plans to convert the fuel source for VAPP from coal to natural gas and anticipate that the conversion will be completed by the end of 2015 or early 2016. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC. We filed for a Certificate of Authority from the PSCW on April 26, 2013, and received preliminary approval on January 30, 2014. We expect to receive a final written order by the end of the first quarter. We received a construction air permit from the WDNR on November 11, 2013.

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Regulatory Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]
Regulatory assets earnings return based on short-term rates	$ 82.7
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	10.1
Regulatory Assets
Regulatory Assets	1,108.5	1,380.3
Deferred unrecognized pension costs [Member]
Regulatory Assets
Regulatory Assets	537.6	731.5
Deferred income tax related [Member]
Regulatory Assets
Regulatory Assets	169.5	176.5
Escrowed electric transmission costs [Member]
Regulatory Assets
Regulatory Assets	126.8	114.1
Escrowed conservation [Member]
Regulatory Assets
Regulatory Assets	66.9	73.5
Deferred plant related -- capital lease [Member]
Regulatory Assets
Regulatory Assets	56.5	66.6
Deferred environmental costs [Member]
Regulatory Assets
Regulatory Assets	47.0	47.4
Other, net [Member]
Regulatory Assets
Regulatory Assets	$ 104.2	$ 170.7

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Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting (Tables) [Abstract]

Financial information of reportable operating segments

Summarized financial information concerning our reportable segments for each of the three years ended December 31, 2013 is shown in the following table.

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2013
Operating Revenues (b)	$	4,462.0	$	446.7	$	1.3		$	(391.0	)	$	4,519.0
Depreciation and Amortization	$	320.2	$	67.1	$	0.8		$	—		$	388.1
Operating Income (Loss)	$	719.4	$	367.1	$	(6.4	)	$	—		$	1,080.1
Equity in Earnings of Unconsolidated Affiliates	$	68.5	$	—	$	(0.1	)	$	—		$	68.4
Interest Expense, Net	$	136.2	$	65.7	$	50.8		$	(0.6	)	$	252.1
Income Tax Expense (Benefit)	$	243.6	$	120.2	$	(25.9	)	$	—		$	337.9
Net Income (Loss)	$	425.1	$	181.6	$	577.2		$	(606.5	)	$	577.4
Capital Expenditures	$	657.9	$	26.1	$	3.4		$	—		$	687.4
Total Assets (c)	$	14,460.4	$	2,846.5	$	4,719.5		$	(7,257.0	)	$	14,769.4

December 31, 2012
Operating Revenues (b)	$	4,190.8	$	439.9	$	1.2		$	(385.5	)	$	4,246.4
Depreciation and Amortization	$	296.4	$	67.1	$	0.7		$	—		$	364.2
Operating Income (Loss)	$	647.7	$	358.8	$	(6.2	)	$	—		$	1,000.3
Equity in Earnings of Unconsolidated Affiliates	$	65.7	$	—	$	(0.2	)	$	—		$	65.5
Interest Expense, Net	$	129.4	$	66.7	$	52.5		$	(0.4	)	$	248.2
Income Tax Expense (Benefit)	$	214.9	$	116.6	$	(25.2	)	$	—		$	306.3
Net Income (Loss)	$	400.6	$	175.9	$	546.1		$	(576.3	)	$	546.3
Capital Expenditures	$	697.3	$	5.5	$	4.2		$	—		$	707.0
Total Assets (c)	$	13,988.1	$	2,903.5	$	4,431.4		$	(7,038.0	)	$	14,285.0

December 31, 2011
Operating Revenues (b)	$	4,431.5	$	435.1	$	0.9		$	(381.1	)	$	4,486.4
Depreciation and Amortization	$	257.0	$	72.5	$	0.7		$	—		$	330.2
Operating Income (Loss)	$	544.8	$	348.9	$	(6.4	)	$	—		$	887.3
Equity in Earnings of Unconsolidated Affiliates	$	62.5	$	—	$	(0.9	)	$	—		$	61.6
Interest Expense, Net	$	110.0	$	66.7	$	59.5		$	(0.4	)	$	235.8
Income Tax Expense (Benefit)	$	182.7	$	112.8	$	(31.6	)	$	—		$	263.9
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	13.4		$	—		$	13.4
Net Income (Loss)	$	376.3	$	169.8	$	525.9		$	(545.8	)	$	526.2
Capital Expenditures	$	792.2	$	31.2	$	7.4		$	—		$	830.8
Total Assets (c)	$	13,433.5	$	2,949.0	$	4,694.8		$	(7,215.2	)	$	13,862.1

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

(c) An elimination of $2,231.2 million, $2,286.7 million and $2,369.0 million is included in Total Assets as of December 31, 2013, 2012 and 2011, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Future minimum payments for the next five years and thereafter for our operating lease contracts
2014	$ 3.9
2015	3.9
2016	3.7
2017	3.1
2018	3.2
Thereafter	22.7
Total	40.5
Manufactured Gas Plant Sites [Member]
Commitment and Contingencies (Textuals) [Abstract]
Reserves related to future remediation costs	36.9	38.2
Commitments and Contingencies (Textuals) [Abstract]
Estimated future detailed site investigation and remediation costs, minimum	19
Estimated Future detailed site investigation and remediation costs, maximum	56
Period for future costs of detailed site investigation and remediation costs	over the next ten years
Period to recover remediation cost of manufactured gas plant sites	5 years
Coal combustion product landfill sites [Member]
Commitment and Contingencies (Textuals) [Abstract]
Expense related to environmental remediation	0.1	0.3	0.2
Reserves related to landfill sites	0
Commitments and Contingencies (Textuals) [Abstract]
Expense related to environmental remediation	0.1	0.3	0.2
Minimum [Member]
Commitments and Contingencies [Line Items]
VAPP Conversion Cost	65
Maximum [Member]
Commitments and Contingencies [Line Items]
VAPP Conversion Cost	$ 70

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Long-Term Debt and Capital Lease Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Long-Term Debt and Capital Lease Obligations (Tables) [Abstract]

Long-term debt outstanding maturities and sinking fund requirements

Debentures and Notes:   As of December 31, 2013, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:

	(Millions of Dollars)
2014	$	322.4
2015	399.5
2016	27.4
2017	29.5
2018	281.1
Thereafter	3,566.8
Total	$	4,626.7

Summary of capitalized leased facilities

The following is a summary of our capitalized leased facilities as of December 31:

Capital Lease Assets	2013			2012
	(Millions of Dollars)
Leased Facilities
Long-term power purchase commitment	$	140.3		$	140.3
Accumulated amortization	(92.5		)	(86.8		)
Total Leased Facilities	$	47.8		$	53.5

Future minimum lease payments under capital lease and present value of net minimum lease payments

Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2013 are as follows:

	(Millions of Dollars)
2014	$	41.9
2015	43.5
2016	45.1
2017	13.9
2018	14.7
Thereafter	56.8
Total Minimum Lease Payments	215.9
Less:  Estimated Executory Costs	(61.7		)
Net Minimum Lease Payments	154.2
Less:  Interest	(49.9		)
Present Value of Net
Minimum Lease Payments	104.3
Less:  Due Currently	(19.8		)
	$	84.5

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Asset Sales, Divestitures And Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Net impacts of the discontinued operations on earnings
Income from Continuing Operations	$ 577.4		$ 546.3		$ 512.8
Income from Discontinued Operations, Net of Tax	0		0		13.4
Net Income	577.4		546.3		526.2
Asset Sales, Divestitures and Discontinued Operations (Textuals) [Abstract]
Ownership percentage in Edgewater Generating Unit 5 sold					25.00%
Proceeds From Sale Of Interest In Unit					38
Other Operations [Member]
Net impacts of the discontinued operations on earnings
Income from Discontinued Operations, Net of Tax	$ 0	[1]	$ 0	[1]	$ 13.4	[1]

[1] Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Assets:
Restricted Cash		$ 2.7
Derivative, Asset	11.8	19.2
Total	11.8	21.9
Liabilities:
Derivative, Liability	0.3	1.9
Total	0.3	1.9
Fair Value, Inputs, Level 1 [Member]
Assets:
Restricted Cash		2.7
Derivative, Asset	5.7	2.2
Total	5.7	4.9
Liabilities:
Derivative, Liability	0	1.9
Total	0	1.9
Fair Value, Inputs, Level 2 [Member]
Assets:
Restricted Cash		0
Derivative, Asset	2.6	12.3
Total	2.6	12.3
Liabilities:
Derivative, Liability	0.3	0
Total	0.3	0
Fair Value, Inputs, Level 3 [Member]
Assets:
Restricted Cash		0
Derivative, Asset	3.5	4.7
Total	3.5	4.7
Liabilities:
Derivative, Liability	0	0
Total	$ 0	$ 0

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Long-Term Debt and Capital Lease Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 Megawatt		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2009
Long-term debt outstanding maturities and sinking fund requirements
Next year	$ 322.4
Year 2	399.5
Year 3	27.4
Year 4	29.5
Year 5	281.1
Thereafter	3,566.8
Total	4,626.7
Summary of capitalized leased facilities
Long-term power purchase commitment	140.3		140.3
Accumulated amortization	(92.5)		(86.8)
Total Leased Facilities	47.8		53.5
Future minimum lease payments under capital lease and present value of net minimum lease payments
Due next year	41.9
Due in two years	43.5
Due in three years	45.1
Due in four years	13.9
Due in five years	14.7
Thereafter	56.8
Total Minimum Lease Payments	215.9
Less: Estimated Executory Costs	(61.7)
Capital Leases Future Minimum Payments Due, Less Executory Costs	154.2
Less: Interest	(49.9)
Net Minimum Lease Payments	104.3
Less: Due Currently	(19.8)
Future minimum lease payments under our capital lease and the present value of our net minimum lease payments	84.5
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt	251.0		251.8		720.0
Number of series of tax-exempt pollution control refunding bonds	2
Restriction under RCC	The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.
Period of Power purchase contract with an unaffiliated independent power producer	25 years
Power capacity from a gas-fired cogeneration facility under capital lease (MW)	236
Minimum energy requirement in gas-fired cogeneration facility	0
Power purchase contract expiration year	Dec. 31, 2022
Power purchase contract expected future renewable period	10 years
Total operating lease payment	33.7		32.5
Increase in regulatory asset due to minimum lease payment						78.5
Regulatory asset value at the end of life of contract	0
Total capital lease obligation	104.3		120.0
Capital lease obligation at the end of life of contract	0
Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Secured Long-term Debt, Noncurrent	275.0	[1]	275.0	[1]
Debt instrument interest rate stated percentage rate	6.09%		6.09%
Notes (unsecured), 6.20% due 2033 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent	200.0		200.0
Debt instrument interest rate stated percentage rate	6.20%		6.20%
Parent Company [Member]
Long-term debt outstanding maturities and sinking fund requirements
Next year	0
Year 2	0
Year 3	0
Year 4	0
Year 5	0
Thereafter	700.0
Total	700.0
Wisconsin Electric [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent	$ 147.0		$ 147.0

[1] (c) Senior notes are secured by a collateral assignment of the leases between ERGSS and Wisconsin Electric related to OC 1 and 2.

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Summary of Significant Accounting Policies (Details 1)	12 Months Ended
	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
ATC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	26.20%
Voting rights in ATC board members	one out of ten
Number of votes with each member of ATC	1
Maximum voting control for individual member in ATC	10.00%

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Consolidated Statements of Capitalization (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Debentures (unsecured), 4.50% due 2013 [Member]
Debt instrument stated interest rate (percentage)	4.50%	4.50%
Debentures (unsecured), 6.60% due 2013 [Member]
Debt instrument stated interest rate (percentage)	6.60%	6.60%
Debentures (unsecured), 6.00% due 2014 [Member]
Debt instrument stated interest rate (percentage)	6.00%	6.00%
Debentures (unsecured), 5.20% due 2015 [Member]
Debt instrument stated interest rate (percentage)	5.20%	5.20%
Debentures (unsecured), 6.25% due 2015 [Member]
Debt instrument stated interest rate (percentage)	6.25%	6.25%
Debentures (unsecured), 1.70% due 2018 [Member]
Debt instrument stated interest rate (percentage)	1.70%	1.70%
Debentures (unsecured), 4.25% due 2019 [Member]
Debt instrument stated interest rate (percentage)	4.25%	4.25%
Debentures (unsecured) 2.95% due 2021 [Member]
Debt instrument stated interest rate (percentage)	2.95%	2.95%
Debentures (unsecured), 6-1/2% due 2028 [Member]
Debt instrument stated interest rate (percentage)	6.50%	6.50%
Debentures (unsecured), 5.625% due 2033 [Member]
Debt instrument stated interest rate (percentage)	5.625%	5.625%
Debentures (unsecured), 5.90% due 2035 [Member]
Debt instrument stated interest rate (percentage)	5.90%	5.90%
Debentures (unsecured), 5.70% due 2036 [Member]
Debt instrument stated interest rate (percentage)	5.70%	5.70%
Debentures (unsecured), 3.65% due 2042 [Member]
Debt instrument stated interest rate (percentage)	3.65%	3.65%
Debentures (unsecured), 6-7/8% due 2095 [Member]
Debt instrument stated interest rate (percentage)	6.875%	6.875%
Notes (secured, nonrecourse), 4.81% effective rate due 2030 [Member]
Debt instrument stated interest rate (percentage)	4.81%	4.81%
Notes (secured, nonrecourse), 4.91% due 2013-2030 [Member] [Member]
Debt instrument stated interest rate (percentage)	4.91%	4.91%
Notes (secured, nonrecourse), 5.209% due 2013-2030 [Member] [Member]
Debt instrument stated interest rate (percentage)	5.209%	5.209%
Notes (secured, nonrecourse), 4.673% due 2013-2031 [Member] [Member]
Debt instrument stated interest rate (percentage)	4.673%	4.673%
Notes (secured, nonrecourse), 6.00% due 2013-2033 [Member] [Member]
Debt instrument stated interest rate (percentage)	6.00%	6.00%
Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Debt instrument stated interest rate (percentage)	6.09%	6.09%
Notes (secured, nonrecourse), 5.848% due 2031-2041 [Member]
Debt instrument stated interest rate (percentage)	5.848%	5.848%
Notes (secured, nonrecourse) 6.00% due 2021 [Member]
Debt instrument stated interest rate (percentage)	6.00%	6.00%
Notes (unsecured), 6.51% due 2013 [Member]
Debt instrument stated interest rate (percentage)	6.51%	6.51%
Notes (unsecured), 6.94% due 2028 [Member]
Debt instrument stated interest rate (percentage)	6.94%	6.94%
Notes (unsecured), 0.504% variable rate due 2016 [Member]
Long-term debt, percentage bearing variable interest rate	0.504%	0.504%
Notes (unsecured), 0.504% variable rate due 2030 [Member]
Long-term debt, percentage bearing variable interest rate	0.504%	0.504%
Notes (unsecured), 6.20% due 2033 [Member]
Debt instrument stated interest rate (percentage)	6.20%	6.20%
Junior Notes (unsecured), 6.25% due 2067 [Member]
Debt instrument stated interest rate (percentage)	6.25%	6.25%
Wisconsin Energy Corporation [Member]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	15,000,000	15,000,000
Preferred stock, shares outstanding	0	0
Six Per Cent. Preferred Stock [Member]
Preferred stock, shares authorized	45,000
Preferred stock, shares outstanding	44,498
Six Per Cent. Preferred Stock [Member] | Wisconsin Electric [Member]
Preferred stock, par value	$ 100	$ 100
Preferred stock, shares authorized		45,000
Preferred stock, shares outstanding		44,498
Preferred stock dividend rate, percentage	6.00%	6.00%
Serial preferred stock, 3.60% Series Redeemable [Member]
Preferred stock, shares outstanding	260,000
Serial preferred stock, 3.60% Series Redeemable [Member] | Wisconsin Electric [Member]
Preferred stock, par value	$ 100	$ 100
Preferred stock, shares outstanding		260,000
Preferred stock dividend rate, percentage	3.60%	3.60%

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Short-Term Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Short-Term Debt (Textuals) [Abstract]
Undrawn lines under bank back-up credit facilities	$ 1,200,000,000
Short-term debt outstanding supported by the available lines of credit	537,400,000
Wisconsin Energy Corporation [Member]
Short-Term Debt (Textuals) [Abstract]
Minimum total funded debt to capitalization ratio	70.00%
Wisconsin Electric [Member]
Short-Term Debt (Textuals) [Abstract]
Minimum total funded debt to capitalization ratio	65.00%
Wisconsin Gas [Member]
Short-Term Debt (Textuals) [Abstract]
Minimum total funded debt to capitalization ratio	65.00%
Commercial Paper [Member]
Short-term notes payable balances and their corresponding weighted-average interest rates
Commercial paper, balance	537,400,000	394,600,000
Commercial paper, weighted-average interest rate	0.20%	0.30%
Commercial paper [Abstract]
Maximum Short-Term Debt Outstanding	594,500,000	669,900,000
Average Short-Term Debt Outstanding	$ 359,100,000	$ 481,600,000
Weighted-Average Interest Rate	0.25%	0.28%

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Related Parties Material related party transactions (Tables)

12 Months Ended

Dec. 31, 2013

Material Related Party Transactions [Abstract]

Provided and received services from the associated companies

RELATED PARTIES

We receive and/or provide certain services to other associated companies in which we have an equity investment.

American Transmission Company LLC:   As of December 31, 2013, we have a 26.2% 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, including the generating units constructed as part of our PTF strategy. ATC reimburses us for these costs when new generation is placed in service.

The following table summarizes material related party transactions with ATC during 2013, 2012 and 2011:

Equity Investee	2013		2012		2011
	(Millions of Dollars)
Equity in Earnings	$	68.5	$	65.7	$	62.5
Distributions Received	$	54.5	$	52.6	$	49.7
Services Provided	$	9.0	$	8.2	$	10.8
Services Received	$	234.2	$	222.7	$	219.2

As of December 31, 2013 and 2012, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:

Equity Investee	2013		2012
	(Millions of Dollars)
Accounts Receivable
Services provided	$	0.6	$	0.5
Accounts Payable
Services received	$	19.5	$	18.6

Receivable and payable balances with ATC

As of December 31, 2013 and 2012, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:

Equity Investee	2013		2012
	(Millions of Dollars)
Accounts Receivable
Services provided	$	0.6	$	0.5
Accounts Payable
Services received	$	19.5	$	18.6

Material related party transactions with ATC [Table Text Block]

The following table summarizes material related party transactions with ATC during 2013, 2012 and 2011:

Equity Investee	2013		2012		2011
	(Millions of Dollars)
Equity in Earnings	$	68.5	$	65.7	$	62.5
Distributions Received	$	54.5	$	52.6	$	49.7
Services Provided	$	9.0	$	8.2	$	10.8
Services Received	$	234.2	$	222.7	$	219.2

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Preferred Stock (Notes)

12 Months Ended

Dec. 31, 2013

Preferred Stock [Abstract]

Preferred Stock [Text Block]

PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2013 and 2012:

	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
					(In Millions)
Wisconsin Energy
$.01 par value Preferred Stock	15,000,000	—	—		$	—
Wisconsin Electric
$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 of subsidiary					$	30.4

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2013

Valuation and Qualifying Accounts [Abstract]

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

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, 2013	$	58.0	$	49.4	$	0.4		$	(46.8	)	$	61.0
December 31, 2012	$	61.7	$	47.7	$	(4.0	)	$	(47.4	)	$	58.0
December 31, 2011	$	58.1	$	85.8	$	(35.9	)	$	(46.3	)	$	61.7

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Common Equity (Details) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended				12 Months Ended
	Jan. 31, 2014	Jan. 31, 2013	Jan. 31, 2012	Jan. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common Stock, Shares Authorized					325,000,000	325,000,000
Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors
Share-based compensation expense					$ 19.0	$ 22.0	$ 28.5
Common Equity (Textuals)
Actual tax benefit realized for the tax deductions from option exercises/settlement					17.8	0	14.3
Common Stock, Shares, Outstanding					225,962,959	229,039,456
Related Tax Benefit					7.6	8.8	11.4
Maximum [Member]
Common Equity (Textuals)
Requirement to maintain common equity ratio by Wisconsin Electric					53.50%
Requirement to maintain common equity ratio by Wisconsin Gas					50.00%
Minimum [Member]
Common Equity (Textuals)
Requirement to maintain common equity ratio by Wisconsin Electric					48.50%
Requirement to maintain common equity ratio by Wisconsin Gas					45.00%
Performance Units [Member]
Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors
Share-based compensation expense					12.7	16.3	24.1
Related Tax Benefit					5.3	7.0	9.7
Restricted stock activity
Granted, Number of Shares	233,735	239,120	346,570	435,690
Common Equity (Textuals)
Unrecognized total compensation costs related share based compensation					10.8
Months, on a weighted-average basis, expected for recognizing total compensation costs related to non-vested stock options					20 months
Intrinsic Value					14.8	19.3	26.7
Stock Options [Member]
Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors
Share-based compensation expense					3.9	2.7	2.6
Non-Vested Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value						$ 3.31
Common Equity (Textuals)
Unrecognized total compensation costs related share based compensation					2.0
Months, on a weighted-average basis, expected for recognizing total compensation costs related to non-vested stock options					21 months
Restricted Stock [Member]
Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors
Share-based compensation expense					2.4	3.0	1.8
Related Tax Benefit					1.3	0	0.8
Restricted stock activity
Outstanding	150,698	188,222			188,222
Granted, Number of Shares	71,504				74,290
Granted, Weighted-Average Market Price					$ 37.65
Released, Number of Shares					(97,973)
Released, Weighted-Average Market Price					$ 26.65
Forfeited, Number of Shares					(13,841)
Forfeited, Weighted-Average Market Price					$ 33.35
Outstanding					150,698	188,222
Common Equity (Textuals)
Unrecognized total compensation costs related share based compensation					2.6
Months, on a weighted-average basis, expected for recognizing total compensation costs related to non-vested stock options					20 months
Restricted stock vesting period in years	3 years
Intrinsic Value					$ 4.0	$ 3.5	$ 2.5

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies (Tables) [Abstract]

Future minimum payments for the next five years and thereafter for our operating lease contracts

Future minimum payments for the next five years and thereafter for our operating lease contracts are as follows:

	(Millions of Dollars)
2014	$	3.9
2015	3.9
2016	3.7
2017	3.1
2018	3.2
Thereafter	22.7
Total	$	40.5

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies (Policies) [Abstract]

Consolidation

General:Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our subsidiaries in the following reportable segments:

• Utility Energy Segment -- Consisting of Wisconsin Electric and Wisconsin Gas, engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and

• Non-Utility Energy Segment -- Consisting primarily of We Power, engaged principally in the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Our Corporate and Other segment includes Wispark, which develops and invests in real estate. We have also eliminated all intercompany transactions from the consolidated financial statements.

Basis of Accounting

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.

Reclassifications

Reclassifications and Adjustments:As of December 31, 2013, we have presented the tax effect of net operating loss carryforwards within current deferred tax assets, net on the consolidated balance sheets. As of December 31, 2012, $59.0 million representing the tax effect of net operating loss carryforwards were included in income taxes receivable, which is a line item that has now been condensed within other current assets on the consolidated balance sheets. This $59.0 million amount has been adjusted in the consolidated balance sheets as of December 31, 2012 to conform to the December 31, 2013 presentation, and conforming changes have been made in the consolidated statements of cash flows and in the notes to the consolidated financial statements. For additional information related to our deferred tax assets, see Note G.

In addition, we have adjusted the presentation of regulatory assets and liabilities to present amounts as noncurrent assets and liabilities on the consolidated balance sheets. Prior period amounts recorded within other current assets and liabilities have been reclassified to conform to the current presentation. For additional information related to regulatory assets and liabilities, see Note C.

Revenues

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.

We recognize We Power revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease.

Accounting For MISO Energy Transactions

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.

Property and Depreciation

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.

We recorded the following property in service by segment as of December 31:

Property In Service	2013		2012
	(Millions of Dollars)
Utility Energy	$	11,779.8	$	11,080.9
Non-Utility Energy	3,091.3		3,068.5
Other	95.2		89.4
Total	$	14,966.3	$	14,238.8

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 2013 and 2012, and 2.8% in 2011.

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.

Our regulated utilities collect in their 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 $724.5 million as of December 31, 2013 and $725.0 million as of December 31, 2012.

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2013		2012
	(Millions of Dollars)
Utility Energy	$	132.7	$	298.2
Non-Utility Energy	16.5		13.3
Other	0.4		4.4
Total	$	149.6	$	315.9

Allowance For Funds Used During Construction - Regulated

Allowance For Funds Used During Construction - Regulated:   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.

Capitalized Interest And Carrying Costs Non Regulated Energy Policy [Text Block]

Capitalized Interest and Carrying Costs - Non-Regulated Energy:   As part of the construction of the PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheet and we are amortizing the deferred carrying costs to revenue over the individual lease terms.

Earning per Common Share

Earnings per Common Share:   We compute basic earnings per common share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. All stock options outstanding during 2013, 2012 and 2011 were included in the computation of diluted earnings per share. Anti-dilutive shares are excluded from the calculation.

Materials, Supplies and Inventories

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

Materials, Supplies and Inventories	2013		2012
	(Millions of Dollars)
Fossil Fuel	$	117.7	$	165.5
Materials and Supplies	133.9		121.9
Natural Gas in Storage	77.8		73.3
Total	$	329.4	$	360.7

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

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

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

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

Cash and Cash Equivalents

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

Margin Accounts

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

Goodwill

Goodwill:   Goodwill reflects the cost of an acquisition in excess of the fair values assigned to identifiable net assets acquired. As of December 31, 2013 and 2012, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.

Goodwill is not subject to amortization. However, it is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. Fair value is assessed by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2013 impairment test date.

Impairment or Disposal of Long Lived Assets

Impairment or Disposal of Long Lived Assets:   We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2013, 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

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 26.2% in ATC as of December 31, 2013 and 2012. 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

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. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note G.

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

Stock Options:   We estimate the fair value of stock options using the binomial pricing model. We report unearned stock-based compensation associated with non-vested restricted stock and performance share awards activity within Other Paid in Capital in our Consolidated Statements of Common Equity. We report excess tax benefits as a financing cash inflow. 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 grant date. For a discussion of the impacts to our Consolidated Financial Statements, see Note H.

Treasury Grant Accounting Policy [Policy Text Block]

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 this will continue into 2014. As of December 31, 2013, $48.0 million was recognized as income, which reflects the amount that was returned to customers in the form of bill credits during the year. We recorded an $82.6 million receivable, and deferred the balance that we expect to benefit our customers in the future. The accounting reflects the regulatory treatment of the grant.

The PSCW approved escrow accounting treatment for the Treasury Grant. Under escrow accounting, we true-up any differences between the actual grant proceeds received and the grant proceeds passed on to customers in the form of bill credits.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies (Tables) [Abstract]

Other Income and Deductions, Net

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	2013		2012			2011
	(Millions of Dollars)
AFUDC - Equity	$	18.3	$	35.3		$	59.4
Other, net	0.5		(0.5		)	3.3
Total Other Income and Deductions, net	$	18.8	$	34.8		$	62.7

Property In Service By Segment

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.

We recorded the following property in service by segment as of December 31:

Property In Service	2013		2012
	(Millions of Dollars)
Utility Energy	$	11,779.8	$	11,080.9
Non-Utility Energy	3,091.3		3,068.5
Other	95.2		89.4
Total	$	14,966.3	$	14,238.8

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 2013 and 2012, and 2.8% in 2011.

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.

Our regulated utilities collect in their 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 $724.5 million as of December 31, 2013 and $725.0 million as of December 31, 2012.

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2013		2012
	(Millions of Dollars)
Utility Energy	$	132.7	$	298.2
Non-Utility Energy	16.5		13.3
Other	0.4		4.4
Total	$	149.6	$	315.9

Construction Work in Progress (CWIP) by segment

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2013		2012
	(Millions of Dollars)
Utility Energy	$	132.7	$	298.2
Non-Utility Energy	16.5		13.3
Other	0.4		4.4
Total	$	149.6	$	315.9

Allowance For Funds Used During Construction

Our regulated utility segment recorded the following AFUDC for the years ended December 31:

	2013		2012		2011
	(Millions of Dollars)
AFUDC - Debt	$	7.7	$	14.7	$	24.7
AFUDC - Equity	$	18.3	$	35.3	$	59.4

Inventories

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

Materials, Supplies and Inventories	2013		2012
	(Millions of Dollars)
Fossil Fuel	$	117.7	$	165.5
Materials and Supplies	133.9		121.9
Natural Gas in Storage	77.8		73.3
Total	$	329.4	$	360.7

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

Fair value of stock options

The fair value of our stock options was calculated using a binomial option-pricing model using the following weighted-average assumptions:

	2013	2012	2011
Risk-free interest rate	0.1% - 1.9%	0.1% - 2.0%	0.2% - 3.4%
Dividend yield	3.7%	3.9%	3.9%
Expected volatility	18.0%	19.0%	19.0%
Expected life (years)	5.9	5.9	5.5
Expected forfeiture rate	2.0%	2.0%	2.0%
Weighted-average fair value
of our stock options granted	$3.45	$3.34	$3.17

Property In Services By Segment [Text Block]

We recorded the following property in service by segment as of December 31:

Property In Service	2013		2012
	(Millions of Dollars)
Utility Energy	$	11,779.8	$	11,080.9
Non-Utility Energy	3,091.3		3,068.5
Other	95.2		89.4
Total	$	14,966.3	$	14,238.8

XML

Consolidated Statements of Capitalization (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Common Equity	$ 4,233.0		$ 4,135.1
Preferred Stock	30.4		30.4
Obligations under capital leases	104.3		120.0
Unamortized discount, net and other	(25.6)		(27.0)
Long-term debt due currently	(342.2)		(412.1)
Total Long-Term Debt	4,363.2		4,453.8
Total Capitalization	8,626.6		8,619.3
Debentures (unsecured), 4.50% due 2013 [Member]
Long-Term debt, Unsecured	0		300.0
Debentures (unsecured), 6.60% due 2013 [Member]
Long-Term debt, Unsecured	0		45.0
Debentures (unsecured), 6.00% due 2014 [Member]
Long-Term debt, Unsecured	300.0		300.0
Debentures (unsecured), 5.20% due 2015 [Member]
Long-Term debt, Unsecured	125.0		125.0
Debentures (unsecured), 6.25% due 2015 [Member]
Long-Term debt, Unsecured	250.0		250.0
Debentures (unsecured), 1.70% due 2018 [Member]
Long-Term debt, Unsecured	250.0		0
Debentures (unsecured), 4.25% due 2019 [Member]
Long-Term debt, Unsecured	250.0		250.0
Debentures (unsecured) 2.95% due 2021 [Member]
Long-Term debt, Unsecured	300.0		300.0
Debentures (unsecured), 6-1/2% due 2028 [Member]
Long-Term debt, Unsecured	150.0		150.0
Debentures (unsecured), 5.625% due 2033 [Member]
Long-Term debt, Unsecured	335.0		335.0
Debentures (unsecured), 5.90% due 2035 [Member]
Long-Term debt, Unsecured	90.0		90.0
Notes (secured, nonrecourse), 4.91% due 2013-2030 [Member] [Member]
Long-Term debt, Secured	122.1	[1]	126.7	[1]
Debentures (unsecured), 5.70% due 2036 [Member]
Long-Term debt, Unsecured	300.0		300.0
Debentures (unsecured), 3.65% due 2042 [Member]
Long-Term debt, Unsecured	250.0		250.0
Debentures (unsecured), 6-7/8% due 2095 [Member]
Long-Term debt, Unsecured	100.0		100.0
Notes (secured, nonrecourse), 4.81% effective rate due 2030 [Member]
Long-Term debt, Secured	2.0		2.0
Notes (secured, nonrecourse), 5.209% due 2013-2030 [Member] [Member]
Long-Term debt, Secured	231.5	[2]	238.6	[2]
Notes (secured, nonrecourse), 4.673% due 2013-2031 [Member] [Member]
Long-Term debt, Secured	190.9	[2]	196.7	[2]
Notes (secured, nonrecourse), 6.00% due 2013-2033 [Member] [Member]
Long-Term debt, Secured	138.4	[1]	142.1	[1]
Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Long-Term debt, Secured	275.0	[2]	275.0	[2]
Notes (secured, nonrecourse), 5.848% due 2031-2041 [Member]
Long-Term debt, Secured	215.0	[2]	215.0	[2]
Notes (secured, nonrecourse) 6.00% due 2021 [Member]
Long-Term debt, Secured	1.8		1.8
Notes (unsecured), 6.51% due 2013 [Member]
Long-Term debt, Unsecured	0		30.0
Notes (unsecured), 6.94% due 2028 [Member]
Long-Term debt, Unsecured	50.0		50.0
Notes (unsecured), 0.504% variable rate due 2016 [Member]
Long-Term debt, Unsecured	67.0	[3]	67.0	[3]
Notes (unsecured), 0.504% variable rate due 2030 [Member]
Long-Term debt, Unsecured	80.0	[3]	80.0	[3]
Notes (unsecured), 6.20% due 2033 [Member]
Long-Term debt, Unsecured	200.0		200.0
Junior Notes (unsecured), 6.25% due 2067 [Member]
Long-Term debt, Unsecured	500.0		500.0
Wisconsin Energy Corporation [Member]
Preferred Stock	0		0
Wisconsin Electric [Member]
Preferred Stock	30.4		30.4
Long-Term debt, Unsecured	147.0		147.0
Six Per Cent. Preferred Stock [Member]
Preferred Stock	4.4
Six Per Cent. Preferred Stock [Member] | Wisconsin Electric [Member]
Preferred Stock			4.4
Serial preferred stock, 3.60% Series Redeemable [Member]
Preferred Stock	26.0
Serial preferred stock, 3.60% Series Redeemable [Member] | Wisconsin Electric [Member]
Preferred Stock			26.0
Serial preferred stock, $25 par value; authorized 5,000,000 shares; none outstanding [Member]
Preferred Stock	0
Serial preferred stock, $25 par value; authorized 5,000,000 shares; none outstanding [Member] | Wisconsin Electric [Member]
Preferred Stock			$ 0

[1] (b) Senior notes are secured by a collateral assignment of the leases between PWGS and Wisconsin Electric related to PWGS 1 and 2.

[2] (c) Senior notes are secured by a collateral assignment of the leases between ERGSS and Wisconsin Electric related to OC 1 and 2.

[3] Variable interest rate as of December 31, 2013.

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities (Tables) [Abstract]

Regulatory assets and liabilities

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

	2013		2012
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	537.6	$	731.5
Deferred income tax related	169.5		176.5
Escrowed electric transmission costs	126.8		114.1
Escrowed conservation	66.9		73.5
Deferred plant related -- capital lease	56.5		66.6
Deferred environmental costs	47.0		47.4
Other, net	104.2		170.7
Total regulatory assets	$	1,108.5	$	1,380.3
Regulatory Liabilities
Deferred cost of removal obligations	$	724.5	$	725.0
Escrowed bad debt costs	64.6		81.1
Other, net	90.0		62.2
Total regulatory liabilities	$	879.1	$	868.3

XML

Condensed Parent Company Financial Statements (Details 6) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Financial Instruments
Long-term debt including current portion, carrying value	$ 4,626.7	$ 4,772.9
Long-term debt including current portion, fair value	4,911.8	5,447.3
Carrying Amount [Member] | Wisconsin Energy Corporation [Member]
Financial Instruments
Long-term debt including current portion, carrying value	700.0	700.0
Fair Value [Member] | Wisconsin Energy Corporation [Member]
Financial Instruments
Long-term debt including current portion, fair value	$ 749.4	$ 805.9

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Measurements (Tables) [Abstract]

Financial assets and liabilities by level within the fair value hierarchy

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

Recurring Fair Value Measures	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	5.7	$	2.6	$	3.5	11.8
Total	$	5.7	$	2.6	$	3.5	$	11.8
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

Recurring Fair Value Measures	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	2.7	$	—	$	—	$	2.7
Derivatives	2.2		12.3		4.7		19.2
Total	$	4.9	$	12.3	$	4.7	$	21.9
Liabilities:
Derivatives	$	1.9	$	—	$	—	$	1.9
Total	$	1.9	$	—	$	—	$	1.9

Fair value of derivatives classified as Level 3 in the fair value hierarchy

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

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	4.7		$	5.7
Realized and unrealized gains (losses)	—			—
Purchases	10.6			11.0
Issuances	—			—
Settlements	(11.8		)	(12.0		)
Transfers in and/or out of Level 3	—			—
Balance as of December 31	$	3.5		$	4.7
Change in unrealized gains (losses) relating to instruments still held as of December 31	$	—		$	—

Carrying amount and estimated fair value of certain financial instruments

The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2013				2012
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	26.0	$	30.4	$	26.0
Long-term debt including current portion	$	4,626.7	$	4,911.8	$	4,772.9	$	5,447.3

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Change in Asset Retirement Obligations
Balance as of January 1	$ 44.3	$ 55.5
Liabilities settled	(4.4)	(14.0)
Accretion	2.4	2.8
Balance as of December 31	$ 42.3	$ 44.3

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Benefits (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Matching contributions under Savings Plans	$ 14,200,000	$ 13,800,000	$ 14,100,000
A one-percentage-point change in assumed health care cost trend rates effects
1% Increase, in assumed health care cost trend rates, Effect on, Post-retirement benefit obligation	26,400,000
1% Decrease, in assumed health care cost trend rates, Effect on, Post-retirement benefit obligation	(22,300,000)
1% Increase, in assumed health care cost trend rates, Effect on, Total of service and interest cost components	3,200,000
1% Decrease, in assumed health care cost trend rates, Effect on, Total of service and interest cost components	(2,600,000)
Benefits (Textuals) [Abstract]
Health care cost trend rate up to specified age	65
Health care cost trend rate post specified age	65
Current pension plan target asset allocation in equity investments	45.00%
Current pension plan target asset allocation in fixed income investments	55.00%
Other Post-Retirement Employee Benefits target asset allocation in equity investments	60.00%
Other Post-Retirement Employee Benefits target asset allocation in fixed income investments	40.00%
Matching contributions under Savings Plans	14,200,000	13,800,000	14,100,000
Postemployment benefits liability	4,200,000	4,000,000
Pension, Qualified [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Funded Status of Plan	138,700,000	(20,900,000)
Pension, Non-Qualified [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Funded Status of Plan	(97,900,000)	(102,200,000)
Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	1,410,200,000	1,508,500,000	1,330,600,000
Defined Benefit Plan, Amortization of Previously Unrecognized Benefit Costs	38,700,000
Net Periodic Benefit Cost
Service cost	14,600,000	21,700,000	15,900,000
Interest cost	60,400,000	65,500,000	67,600,000
Expected return on plan assets	(95,800,000)	(89,600,000)	(82,100,000)
Amortization of:
Transition obligation	0	0	0
Prior service cost (credit)	2,300,000	2,200,000	2,200,000
Actuarial loss	54,500,000	41,000,000	34,000,000
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	2,500,000	0	0
Curtailment (gain)	0	400,000	0
Net Periodic Benefit Cost	38,500,000	41,200,000	37,600,000
Weighted-Average assumptions used to determine benefit obligations as of Dec. 31
Discount rate	5.00%	4.10%	5.05%
Rate of compensation increase	4.00%	4.00%	4.00%
Weighted-Average assumptions used to determine net cost for year ended Dec. 31
Discount rate	4.10%	5.05%	5.60%
Expected return on plan assets	7.25%	7.25%	7.25%
Rate of compensation increase	4.00%	4.00%	4.00%
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	1,451,000,000	1,385,400,000	1,262,500,000
Employer contributions to defined benefit plan
Employer contributions	8,700,000	102,700,000
Expected benefit payments in future
2012	103,900,000
2013	98,600,000
2014	100,300,000
2015	100,900,000
2016	100,200,000
2017-2021	495,600,000
Pension Plans [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	873,200,000	763,100,000
Pension Plans [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	577,800,000	622,300,000
Pension Plans [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
Pension Plans [Member] | Cash And Cash Equivalents [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	21,000,000	13,700,000
Pension Plans [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	21,000,000	13,700,000
Pension Plans [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
Pension Plans [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
Pension Plans [Member] | U.S. Equity [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	519,500,000	466,300,000
Pension Plans [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	519,500,000	466,300,000
Pension Plans [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
Pension Plans [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
Pension Plans [Member] | International Equity [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	181,900,000	165,100,000
Pension Plans [Member] | International Equity [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	146,200,000	134,700,000
Pension Plans [Member] | International Equity [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	35,700,000	30,400,000
Pension Plans [Member] | International Equity [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
Pension Plans [Member] | U.S. Bonds [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	613,600,000	614,300,000
Pension Plans [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	108,400,000	67,700,000
Pension Plans [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	505,200,000	546,600,000
Pension Plans [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
Pension Plans [Member] | International Bonds [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	115,000,000	126,000,000
Pension Plans [Member] | International Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	78,100,000	80,700,000
Pension Plans [Member] | International Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	36,900,000	45,300,000
Pension Plans [Member] | International Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	362,700,000	381,200,000	389,700,000
Defined Benefit Plan, Amortization of Previously Unrecognized Benefit Costs	(900,000)
Net Periodic Benefit Cost
Service cost	10,000,000	10,300,000	10,400,000
Interest cost	15,600,000	20,300,000	20,800,000
Expected return on plan assets	(21,300,000)	(19,000,000)	(16,900,000)
Amortization of:
Transition obligation	0	300,000	300,000
Prior service cost (credit)	(2,000,000)	(1,900,000)	(1,900,000)
Actuarial loss	3,700,000	7,300,000	6,200,000
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	0	0	0
Curtailment (gain)	0	0	0
Net Periodic Benefit Cost	6,000,000	17,300,000	18,900,000
Weighted-Average assumptions used to determine benefit obligations as of Dec. 31
Discount rate	4.95%	4.15%	5.20%
Weighted-Average assumptions used to determine net cost for year ended Dec. 31
Discount rate	4.15%	5.20%	5.70%
Expected return on plan assets	7.50%	7.50%	7.50%
Assumed health care cost trend rates as of Dec. 31
Health care cost trend rate assumed for next year, Pre 65	0.0750	0.0750	0.0800
Health care cost trend rate assumed for next year, Post 65	0.0750	0.0750	0.1200
Rate that the cost trend rate gradually adjusts to	0.050	0.050	0.050
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)	2021/2021	2017/2017	2017/2017
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	327,600,000	285,400,000	255,400,000
Employer contributions to defined benefit plan
Employer contributions	14,100,000	17,700,000	48,400,000
Expected benefit payments in future
2012	24,200,000
2013	21,600,000
2014	22,000,000
2015	22,600,000
2016	23,400,000
2017-2021	119,700,000
OPEB [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	222,700,000	187,900,000
OPEB [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	104,900,000	97,500,000
OPEB [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
OPEB [Member] | Cash And Cash Equivalents [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	2,600,000	1,700,000
OPEB [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	2,600,000	1,700,000
OPEB [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
OPEB [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
OPEB [Member] | U.S. Equity [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	148,000,000	125,900,000
OPEB [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	148,000,000	125,900,000
OPEB [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
OPEB [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
OPEB [Member] | International Equity [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	49,700,000	42,100,000
OPEB [Member] | International Equity [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	46,900,000	39,900,000
OPEB [Member] | International Equity [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	2,800,000	2,200,000
OPEB [Member] | International Equity [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
OPEB [Member] | U.S. Bonds [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	104,700,000	94,900,000
OPEB [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	8,400,000	5,000,000
OPEB [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	96,300,000	89,900,000
OPEB [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
OPEB [Member] | International Bonds [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	22,600,000	20,800,000
OPEB [Member] | International Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	16,800,000	15,400,000
OPEB [Member] | International Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	5,800,000	5,400,000
OPEB [Member] | International Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets	0	0
Pension, Qualified [Member] | Pension Plans [Member]
Employer contributions to defined benefit plan
Employer contributions	0	95,600,000	236,400,000
Pension, Non-Qualified [Member] | Pension Plans [Member]
Employer contributions to defined benefit plan
Employer contributions	$ 8,700,000	$ 7,100,000	$ 6,500,000

XML

Consolidated Income Statements (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues	$ 4,519.0	$ 4,246.4	$ 4,486.4
Operating Expenses
Fuel and purchased power	1,153.0	1,098.6	1,169.7
Cost of gas sold	674.1	545.8	728.7
Other operation and maintenance	1,155.0	1,116.1	1,256.8
Depreciation and amortization	388.1	364.2	330.2
Property and revenue taxes	116.7	121.4	113.7
Total Operating Expenses	3,486.9	3,246.1	3,599.1
Revenue from Grants	48.0	0	0
Operating Income	1,080.1	1,000.3	887.3
Income (Loss) from Equity Method Investments	68.4	65.5	61.6
Other Income and Deductions, net	18.8	34.8	62.7
Interest Expense, net	252.1	248.2	235.8
Income (Loss) from Continuing Operations Before Income Taxes	915.3	852.6	776.7
Total Income Tax Expense, Amount	337.9	306.3	263.9
Income from Continuing Operations	577.4	546.3	512.8
Income from Discontinued Operations, Net of Tax	0	0	13.4
Net Income	577.4	546.3	526.2
Earnings Per Share (Basic)
Continuing Operations	$ 2.54	$ 2.37	$ 2.20
Discontinued Operations	$ 0.00	$ 0.00	$ 0.06
Total Earnings Per Share (Basic)	$ 2.54	$ 2.37	$ 2.26
Earnings Per Share (Diluted)
Continuing Operations	$ 2.51	$ 2.35	$ 2.18
Discontinued Operations	$ 0.00	$ 0.00	$ 0.06
Total Earnings Per Share (Diluted)	$ 2.51	$ 2.35	$ 2.24
Weighted Average Common Shares Outstanding (Millions)
Basic	227.6	230.2	232.6
Diluted	229.7	232.8	235.4
Transmission Affiliate [Member]
Operating Expenses
Income (Loss) from Equity Method Investments	$ 68.5	$ 65.7	$ 62.5

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2013

Preferred Stock [Abstract]

Preferred Stock [Text Block]

PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2013 and 2012:

	Shares Authorized	Shares Outstanding	Redemption Price Per Share		Total
					(In Millions)
Wisconsin Energy
$.01 par value Preferred Stock	15,000,000	—	—		$	—
Wisconsin Electric
$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 of subsidiary					$	30.4

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Consolidated Statements of Common Equity (USD $) In Millions	Total	Common Stock [Member]	Other Paid In Capital [Member]	Retained Earnings [Member]
Beginning - Balance at Dec. 31, 2010	$ 3,802.1	$ 2.3	$ 721.5	$ 3,078.3
Net income	526.2			526.2
Common stock cash dividends of $1.04, $1.20, and $1.445 per share for Year ended 2011, 2012 and 2013, respectively	(242.0)			(242.0)
Exercise of stock options	54.4		54.4
Purchase of common stock	(193.9)		(193.9)
Tax benefit from share based compensation	11.9		11.9
Stock-based compensation and other	4.6		4.6
Ending - Balance at Dec. 31, 2011	3,963.3	2.3	598.5	3,362.5
Net income	546.3			546.3
Common stock cash dividends of $1.04, $1.20, and $1.445 per share for Year ended 2011, 2012 and 2013, respectively	(276.3)			(276.3)
Exercise of stock options	49.8		49.8
Purchase of common stock	(153.2)		(153.2)
Stock-based compensation and other	5.2		5.2
Ending - Balance at Dec. 31, 2012	4,135.1	2.3	500.3	3,632.5
Net income	577.4			577.4
Common stock cash dividends of $1.04, $1.20, and $1.445 per share for Year ended 2011, 2012 and 2013, respectively	(328.9)			(328.9)
Exercise of stock options	48.5		48.5
Purchase of common stock	(223.4)		(223.4)
Tax benefit from share based compensation	18.1		18.1
Stock-based compensation and other	6.2		6.2
Ending - Balance at Dec. 31, 2013	$ 4,233.0	$ 2.3	$ 349.7	$ 3,881.0

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Common Equity (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Non-vested options
Granted, Weighted-Average Exercise Price	$ 3.45	$ 3.34	$ 3.17
Outstanding, Shares, Ending Balance	8,089,710
Outstanding, Weighted-Average Exercise Price, Ending	$ 26.84
Non-Vested Options [Member]
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 3.31
Non-vested options
Outstanding, Shares, Beginning Balance	1,702,275
Granted, shares	1,418,560
Granted, Weighted-Average Exercise Price	$ 3.45
Vested, shares	(730,015)
Vested, Weighted-Average Exercise Price	$ 3.34
Forfeited, shares	(10,030)
Forfeited, Weighted-Average Exercise Price	$ 3.37
Outstanding, Shares, Ending Balance	2,380,790
Outstanding, Weighted-Average Exercise Price, Ending	$ 3.38

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Taxes (Tables) [Abstract]

Summary of income tax expense

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

Income Taxes	2013			2012			2011
	(Millions of Dollars)
Current tax expense (benefit)	$	25.2		$	13.1		$	(166.7	)
Deferred income taxes, net	313.8			294.4			434.8
Investment tax credit, net	(1.1		)	(1.2		)	(4.2		)
Total Income Tax Expense	$	337.9		$	306.3		$	263.9

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 as a result of the following:

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 as a result of the following:

	2013					2012					2011
				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	$	320.3		35.0	%	$	298.4		35.0	%	$	271.8		35.0	%
State income taxes net of federal tax benefit	49.0			5.3	%	43.3			5.1	%	40.1			5.2	%
Production tax credits	(16.7		)	(1.8	)%	(15.9		)	(1.9	)%	(8.7		)	(1.1	)%
Treasury Grant	(7.4		)	(0.8	)%	—			—	%	—			—	%
AFUDC - Equity	(6.4		)	(0.7	)%	(12.3		)	(1.4	)%	(20.8		)	(2.7	)%
Investment tax credit restored	(1.1		)	(0.1	)%	(1.2		)	(0.1	)%	(4.2		)	(0.5	)%
Domestic production activities deduction	—			—	%	(12.6		)	(1.5	)%	(12.6		)	(1.6	)%
Other, net	0.2			—	%	6.6			0.7	%	(1.7		)	(0.3	)%
Total Income Tax Expense	$	337.9		36.9	%	$	306.3		35.9	%	$	263.9		34.0	%

Components of deferred income taxes classified as net current assets and net long-term liabilities

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	2013		2012
	(Millions of Dollars)
Current
Future federal tax benefits	$	309.7	$	59.0
Employee benefits and compensation	13.8		14.9
Other	56.0		81.1
Total Current Deferred Tax Assets	379.5		155.0
Non-current
Deferred revenues	237.0		250.0
Employee benefits and compensation	95.6		97.0
Future federal tax benefits	32.5		334.7
Property-related	28.2		28.3
Construction advances	18.3		22.2
Other	62.9		16.3
Total Non-Current Deferred Tax Assets	474.5		748.5
Total Deferred Tax Assets	$	854.0	$	903.5

Deferred Tax Liabilities	2013		2012
	(Millions of Dollars)
Current
Prepaid items	$	69.5	$	49.7
Total Current Deferred Tax Liabilities	69.5		49.7
Non-current
Property-related	2,574.4		2,339.4
Employee benefits and compensation	238.5		244.3
Investment in transmission affiliate	169.9		144.9
Deferred transmission costs	50.8		45.7
Other	74.9		91.2
Total Non-current Deferred Tax Liabilities	3,108.5		2,865.5
Total Deferred Tax Liabilities	$	3,178.0	$	2,915.2
Consolidated Balance Sheet Presentation	2013		2012
Current Deferred Tax Asset	$	310.0	$	105.3
Non-Current Deferred Tax Liability	$	2,634.0	$	2,117.0

Reconciliation of the beginning and ending amount of unrecognized tax benefits

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:

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	11.3		$	11.1
Additions for tax positions of prior years	—			10.8
Reductions for tax positions of prior years	(2.9		)	(10.6		)
Balance as of December 31	$	8.4		$	11.3

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Derivative Instruments (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Liabilities [Line Items]
Regulatory liabilities related to derivatives	$ 879.1	$ 868.3
Derivative [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities related to derivatives	$ 9.6	$ 17.5

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Benefits

12 Months Ended

Dec. 31, 2013

General Discussion of Pension and Other Postretirement Benefits [Abstract]

BENEFITS

- BENEFITS

Pensions and Other Post-retirement Benefits:   We have 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.

We also have OPEB plans covering 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.

We use a year-end measurement date to measure the funded status of all of our 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 our pension and OPEB plans qualify as a regulatory asset.

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

	Pension						OPEB
	2013			2012			2013			2012
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,508.5		$	1,330.6		$	381.2		$	389.7
Service cost	14.6			21.7			10.0			10.3
Interest cost	60.4			65.5			15.6			20.3
Participants' contributions	—			—			8.9			9.6
Plan amendments	(1.0		)	—			—			0.5
Actuarial loss (gain)	(81.9		)	166.5			(27.7		)	(23.8		)
Other accrued benefits	—			31.4			—			—
Gross benefits paid	(90.4		)	(107.2		)	(26.3		)	(26.3		)
Federal subsidy on benefits paid	N/A			N/A			1.0			0.9
Benefit Obligation at December 31	$	1,410.2		$	1,508.5		$	362.7		$	381.2
Change in Plan Assets
Fair Value at January 1	$	1,385.4		$	1,262.5		$	285.4		$	255.4
Actual earnings on plan assets	147.3			127.4			45.5			29.0
Employer contributions	8.7			102.7			14.1			17.7
Participants' contributions	—			—			8.9			9.6
Gross benefits paid	(90.4		)	(107.2		)	(26.3		)	(26.3		)
Fair Value at December 31	$	1,451.0		$	1,385.4		$	327.6		$	285.4
Net asset (liability)	$	40.8		$	(123.1	)	$	(35.1	)	$	(95.8	)

As of December 31, 2013, our qualified pension plan was over-funded by $138.7 million and our non-qualified pension plan was under-funded by $97.9 million. As of December 31, 2012, our qualified and non-qualified pension plans were under-funded by $20.9 million and $102.2 million, respectively.

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

	Pension				OPEB
	2013		2012		2013		2012
	(Millions of Dollars)
Other long-term assets	$	138.7	$	—	$	40.2	$	25.1
Other long-term liabilities	$	97.9	$	123.1	$	75.3	$	120.9

The accumulated benefit obligation for all defined pension plans was $1,409.5 million and $1,507.1 million as of December 31, 2013, and 2012, respectively.

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
	2013		2012		2013			2012
	(Millions of Dollars)
Net actuarial loss	$	528.8	$	719.2	$	9.8		$	65.3
Prior service costs (credits)	8.8		12.2		(1.7		)	(3.7		)
Total - Regulatory Assets	$	537.6	$	731.4	$	8.1		$	61.6

We estimate that 2014 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs (credits) referred to above of $38.7 million and $(0.9) million, respectively.

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

	Pension									OPEB
	2013			2012			2011			2013			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	14.6		$	21.7		$	15.9		$	10.0		$	10.3		$	10.4
Interest cost	60.4			65.5			67.6			15.6			20.3			20.8
Expected return on plan assets	(95.8		)	(89.6		)	(82.1		)	(21.3		)	(19.0		)	(16.9		)
Amortization of:
Transition obligation	—			—			—			—			0.3			0.3
Prior service cost (credit)	2.3			2.2			2.2			(2.0		)	(1.9		)	(1.9		)
Actuarial loss	54.5			41.0			34.0			3.7			7.3			6.2
Settlement charge	2.5			—			—			—			—			—
Other	—			0.4			—			—			—			—
Net Periodic Benefit Cost	$	38.5		$	41.2		$	37.6		$	6.0		$	17.3		$	18.9

	Pension			OPEB
	2013	2012	2011	2013	2012	2011
Weighted-Average assumptions used to
determine benefit obligations as of Dec. 31
Discount rate	5.00%	4.10%	5.05%	4.95%	4.15%	5.20%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A
Weighted-Average assumptions used to
determine net cost for year ended Dec. 31
Discount rate	4.10%	5.05%	5.60%	4.15%	5.20%	5.70%
Expected return on plan assets	7.25%	7.25%	7.25%	7.50%	7.50%	7.50%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A

Assumed health care cost trend rates as of Dec. 31	2013	2012	2011
Health care cost trend rate assumed for next year (Pre 65 / Post 65)	7.5%/7.5%	7.5%/7.5%	8.0%/12%
Rate that the cost trend rate gradually adjusts to	5.0%	5.0%	5.0%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)	2021/2021	2017/2017	2017/2017

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2013, 2012 and 2011. We consult with our investment advisors on an annual basis to help us 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.

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	$	26.4	$	(22.3	)
Total of service and interest cost components	$	3.2	$	(2.6	)

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.

Our current pension plan target asset allocation is 45% equity investments and 55% fixed income 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 pension plan assets by asset category within the fair value hierarchy (for further level information, see Note M):

	As of December 31, 2013
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	21.0	$	—	$	—	$	21.0
Equities:
U.S. Equity	519.5		—		—		519.5
International Equity	146.2		35.7		—		181.9
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	108.4		505.2		—		613.6
International Bonds	78.1		36.9		—		115.0
Total	$	873.2	$	577.8	$	—	$	1,451.0

	As of December 31, 2012
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	13.7	$	—	$	—	$	13.7
Equities:
U.S. Equity	466.3		—		—		466.3
International Equity	134.7		30.4		—		165.1
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	67.7		546.6		—		614.3
International Bonds	80.7		45.3		—		126.0
Total	$	763.1	$	622.3	$	—	$	1,385.4

(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 OPEB plan assets by asset category within the fair value hierarchy:

	As of December 31, 2013
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	2.6	$	—	$	—	$	2.6
Equities:
U.S. Equity	148.0		—		—		148.0
International Equity	46.9		2.8		—		49.7
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	8.4		96.3		—		104.7
International Bonds	16.8		5.8		—		22.6
Total	$	222.7	$	104.9	$	—	$	327.6

	As of December 31, 2012
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	1.7	$	—	$	—	$	1.7
Equities:
U.S. Equity	125.9		—		—		125.9
International Equity	39.9		2.2		—		42.1
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	5.0		89.9		—		94.9
International Bonds	15.4		5.4		—		20.8
Total	$	187.9	$	97.5	$	—	$	285.4

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

Cash Flows:   

Historical employer contributions:

	Pension
Year	Qualified		Non-Qualified		OPEB
	(Millions of Dollars)
2011	$	236.4	$	6.5	$	48.4
2012	$	95.6	$	7.1	$	17.7
2013	$	—	$	8.7	$	14.1

Estimated benefit payments:

Year	Pension		Gross OPEB
	(Millions of Dollars)
2014	$	103.9	$	24.2
2015	$	98.6	$	21.6
2016	$	100.3	$	22.0
2017	$	100.9	$	22.6
2018	$	100.2	$	23.4
2019-2023	$	495.6	$	119.7

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 $14.2 million, $13.8 million and $14.1 million during 2013, 2012 and 2011, respectively.

Postemployment Benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $4.2 million and $4.0 million as of December 31, 2013 and 2012, respectively.

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Common Equity (Tables)

12 Months Ended

Dec. 31, 2013

Common Equity (Tables) [Abstract]

Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors as of December 31:

	2013		2012		2011
	(Millions of Dollars)
Performance units	$	12.7	$	16.3	$	24.1
Stock options	3.9		2.7		2.6
Restricted stock	2.4		3.0		1.8
Share-based compensation expense	$	19.0	$	22.0	$	28.5
Related Tax Benefit	$	7.6	$	8.8	$	11.4

Stock option activity

The following is a summary of our stock option activity during 2013:

Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of January 1, 2013	8,919,669		$	23.86
Granted	1,418,560		$	37.46
Exercised	(2,238,489	)	$	21.67
Forfeited	(10,030	)	$	35.37
Outstanding as of December 31, 2013	8,089,710		$	26.84	5.4	$	117.3
Exercisable as of December 31, 2013	5,708,920		$	23.16	4.1	$	103.8

Stock options outstanding

The following table summarizes information about stock options outstanding as of December 31, 2013:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
Range of Exercise Prices	Number of Options	Exercise Price		Remaining Contractual Life (Years)	Number of Options	Exercise Price		Remaining Contractual Life (Years)
$16.72  to  $21.11	2,128,370	$	20.34	3.9	2,128,370	$	20.34	3.9
$23.88  to  $29.35	3,689,900	$	24.65	4.2	3,382,630	$	24.23	4.0
$34.88  to  $37.46	2,271,440	$	36.48	8.6	197,920	$	35.19	8.1
	8,089,710	$	26.84	5.4	5,708,920	$	23.16	4.1

Non-vested options

The following table summarizes information about our non-vested options during 2013:

Non-Vested Stock Options	Number of Options		Weighted- Average Fair Value
Non-Vested as of January 1, 2013	1,702,275		$	3.31
Granted	1,418,560		$	3.45
Vested	(730,015	)	$	3.34
Forfeited	(10,030	)	$	3.37
Non-Vested as of December 31, 2013	2,380,790		$	3.38

Restricted stock activity

Restricted Shares:   The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2013:

Restricted Shares	Number of Shares		Weighted-Average Market Price
Outstanding as of January 1, 2013	188,222
Granted	74,290		$	37.65
Released	(97,973	)	$	26.65
Forfeited	(13,841	)	$	33.35
Outstanding as of December 31, 2013	150,698

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Related Parties

12 Months Ended

Dec. 31, 2013

Related Party Transaction, Due from (to) Related Party [Abstract]

Provided and received services from the associated companies

RELATED PARTIES

We receive and/or provide certain services to other associated companies in which we have an equity investment.

American Transmission Company LLC:   As of December 31, 2013, we have a 26.2% 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, including the generating units constructed as part of our PTF strategy. ATC reimburses us for these costs when new generation is placed in service.

The following table summarizes material related party transactions with ATC during 2013, 2012 and 2011:

Equity Investee	2013		2012		2011
	(Millions of Dollars)
Equity in Earnings	$	68.5	$	65.7	$	62.5
Distributions Received	$	54.5	$	52.6	$	49.7
Services Provided	$	9.0	$	8.2	$	10.8
Services Received	$	234.2	$	222.7	$	219.2

As of December 31, 2013 and 2012, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:

Equity Investee	2013		2012
	(Millions of Dollars)
Accounts Receivable
Services provided	$	0.6	$	0.5
Accounts Payable
Services received	$	19.5	$	18.6

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Fair Value Measurements (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair value of derivatives classified as Level 3 in the fair value hierarchy
Change in unrealized gains (losses) relating to instruments still held as of December 31	$ 0	$ 0
Derivative [Member]
Fair value of derivatives classified as Level 3 in the fair value hierarchy
Beginning Balance	4.7	5.7
Realized and unrealized gains (losses)	0	0
Purchases	10.6	11.0
Issuances	0	0
Settlements	(11.8)	(12.0)
Transfers in and/or out of Level 3	0	0
Ending Balance	$ 3.5	$ 4.7

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Consolidated Statements of Common Equity (Parenthetical) (Retained Earnings [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Retained Earnings [Member]
Common stock cash dividends per share	$ 1.445	$ 1.20	$ 1.04

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Property, Plant and Equipment
In service	$ 14,966.3		$ 14,238.8
Accumulated depreciation	(4,257.1)		(4,036.0)
In service, net	10,709.2		10,202.8
Construction work in progress	149.6		315.9
Leased facilities, net	47.8		53.5
Net Property, Plant and Equipment	10,906.6		10,572.2
Investments
Equity investment in transmission affiliate	402.7		378.3
Other	36.1		35.5
Total Investments	438.8		413.8
Current Assets
Cash and cash equivalents	26.0		35.6
Accounts receivable, net of allowance for doubtful accounts of $61.0 and $58.0	406.0		285.3
Accrued revenues	321.1		278.1
Materials, supplies and inventories	329.4		360.7
Deferred Tax Assets, Net, Current	310.0		105.3
Prepayments	145.7		145.5
Other	12.9		62.1
Total Current Assets	1,551.1		1,272.6
Deferred Charges and Other Assets
Regulatory assets	1,108.5		1,380.3
Goodwill	441.9		441.9
Other	322.5		204.2
Total Deferred Charges and Other Assets	1,872.9		2,026.4
Total Assets	14,769.4	[1]	14,285.0	[1]
Capitalization
Common equity	4,233.0		4,135.1
Preferred Stock	30.4		30.4
Long-term debt	4,363.2		4,453.8
Total Capitalization	8,626.6		8,619.3
Current Liabilities
Long-term debt due currently	342.2		412.1
Short-term debt	537.4		394.6
Accounts payable	342.6		368.4
Accrued payroll and benefits	96.9		100.9
Other	177.3		165.4
Total Current Liabilities	1,496.4		1,441.4
Deferred Credits and Other Liabilities
Regulatory liabilities	879.1		868.4
Deferred income taxes - long-term	2,634.0		2,117.0
Deferred revenue, net	664.2		709.7
Pension and other benefit obligations	173.2		244.0
Other long-term liabilities	295.9		285.2
Total Deferred Credits and Other Liabilities	4,646.4		4,224.3
Commitments and Contingencies (Note Q)
Total Capitalization and Liabilities	$ 14,769.4		$ 14,285.0

[1] An elimination of $2,231.2 million, $2,286.7 million and $2,369.0 million is included in Total Assets as of December 31, 2013, 2012 and 2011, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

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Common Equity

12 Months Ended

Dec. 31, 2013

Stockholders' Equity Note [Abstract]

COMMON EQUITY

 COMMON EQUITY

As of December 31, 2013 and 2012, we had 325,000,000 shares of common stock authorized under our charter, of which 225,962,959 and 229,039,456 common shares, respectively, were outstanding. All share-based compensation is currently fulfilled by purchases on the open market by our independent agents and do not dilute shareholders' ownership.

Share-Based Compensation Plans:   We have a plan that was approved by stockholders that enables us to provide a long-term incentive through equity interests in Wisconsin Energy to outside directors, selected officers and key employees of the Company. The plan provides for the granting of stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in 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 stock options during the period.

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors as of December 31:

	2013		2012		2011
	(Millions of Dollars)
Performance units	$	12.7	$	16.3	$	24.1
Stock options	3.9		2.7		2.6
Restricted stock	2.4		3.0		1.8
Share-based compensation expense	$	19.0	$	22.0	$	28.5
Related Tax Benefit	$	7.6	$	8.8	$	11.4

Stock Options:   The exercise price of a 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 our stock options, see Note A.

We expect that substantially all of the outstanding options as of December 31, 2013 will be exercised.

The following is a summary of our stock option activity during 2013:

Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of January 1, 2013	8,919,669		$	23.86
Granted	1,418,560		$	37.46
Exercised	(2,238,489	)	$	21.67
Forfeited	(10,030	)	$	35.37
Outstanding as of December 31, 2013	8,089,710		$	26.84	5.4	$	117.3
Exercisable as of December 31, 2013	5,708,920		$	23.16	4.1	$	103.8

In January 2014, the Compensation Committee of the Board of Directors (Compensation Committee) awarded 899,500 non-qualified stock options with an exercise price of $41.03 to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

The intrinsic value of options exercised during the years ended December 31, 2013, 2012 and 2011 was $44.5 million, $47.5 million and $36.1 million, respectively. Cash received from options exercised during the years ended December 31, 2013, 2012 and 2011 was $48.5 million, $49.8 million and $54.4 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $17.8 million, zero and $14.3 million, respectively.

The following table summarizes information about stock options outstanding as of December 31, 2013:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
Range of Exercise Prices	Number of Options	Exercise Price		Remaining Contractual Life (Years)	Number of Options	Exercise Price		Remaining Contractual Life (Years)
$16.72  to  $21.11	2,128,370	$	20.34	3.9	2,128,370	$	20.34	3.9
$23.88  to  $29.35	3,689,900	$	24.65	4.2	3,382,630	$	24.23	4.0
$34.88  to  $37.46	2,271,440	$	36.48	8.6	197,920	$	35.19	8.1
	8,089,710	$	26.84	5.4	5,708,920	$	23.16	4.1

The following table summarizes information about our non-vested options during 2013:

Non-Vested Stock Options	Number of Options		Weighted- Average Fair Value
Non-Vested as of January 1, 2013	1,702,275		$	3.31
Granted	1,418,560		$	3.45
Vested	(730,015	)	$	3.34
Forfeited	(10,030	)	$	3.37
Non-Vested as of December 31, 2013	2,380,790		$	3.38

As of December 31, 2013, total compensation costs related to non-vested stock options not yet recognized was approximately $2.0 million, which is expected to be recognized over the next 21 months on a weighted-average basis.

Restricted Shares:   The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2013:

Restricted Shares	Number of Shares		Weighted-Average Market Price
Outstanding as of January 1, 2013	188,222
Granted	74,290		$	37.65
Released	(97,973	)	$	26.65
Forfeited	(13,841	)	$	33.35
Outstanding as of December 31, 2013	150,698

In January 2014, the Compensation Committee awarded 71,504 restricted shares to our directors, officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and generally, 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.

We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards. The intrinsic value of restricted stock vesting was $4.0 million, $3.5 million and $2.5 million for the years ended December 31, 2013, 2012, and 2011, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $1.3 million, zero and $0.8 million, respectively.

As of December 31, 2013, total compensation cost related to restricted stock not yet recognized was approximately $2.6 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Performance Units:   In January 2013, 2012 and 2011, the Compensation Committee awarded 239,120, 346,570 and 435,690 performance units, respectively, to 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 our 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 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, 2013, 2012 and 2011 vested and were settled during the first quarter of 2014, 2013 and 2012, and had a total intrinsic value of $14.8 million, $19.3 million and $26.7 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $5.3 million, $7.0 million and $9.7 million, respectively.

In January 2014, the Compensation Committee awarded 233,735 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

As of December 31, 2013, total compensation cost related to performance units not yet recognized was approximately $10.8 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Restrictions:Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from its non-utility subsidiary, We Power, and its utility subsidiaries.

Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.

Wisconsin Electric and Wisconsin Gas are required to maintain capital structures that differ from GAAP as they reflect regulatory adjustments. The 2013 PSCW rate case order requires Wisconsin Electric to maintain a common equity ratio range of between 48.5% and 53.5%, and Wisconsin Gas to maintain a capital structure which has a common equity range of between 45.0% and 50.0%. Each company is in compliance with its respective common equity range. Wisconsin Electric and Wisconsin Gas must obtain PSCW approval if they pay dividends above the test year levels that would cause either company to fall below the authorized levels of common equity.

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

We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

As of December 31, 2013, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method total approximately $3.6 billion. This amount exceeds 25% of our consolidated net assets as of December 31, 2013.

See Note K for discussion of certain financial covenants related to the bank back-up credit facilities of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.

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

Share Repurchase Program:  We do not expect to issue new shares under our various employee benefit plans and our dividend reinvestment and share purchase plan; rather, we instruct independent plan agents to purchase the shares in the open market. In that regard, no new shares of common stock were issued in 2013, 2012 or 2011.

In May 2011, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock through the end of 2013. Through December 31, 2013, we repurchased approximately 7.7 million shares pursuant to this program at an average cost of $36.19 per share and a total cost of $277.8 million. In addition, through our independent agents, we purchase shares on the open market to fulfill exercised stock options and restricted stock awards. The following table identifies the shares purchased by the Company for the year ending December 31:

	2013			2012			2011
	Shares	Cost		Shares	Cost		Shares	Cost
	(In Millions)
Under May 2011 share repurchase program	3.0	$	126.0	1.5	$	51.8	3.2	$	100.0
To fulfill exercised stock options and restricted stock awards	2.4	97.4		2.8	101.4		3.0	93.9
Total	5.4	$	223.4	4.3	$	153.2	6.2	$	193.9

On December 5, 2013, our Board of Directors authorized a new share repurchase program for management to purchase up to $300 million of the Company's common stock through open market purchases or privately negotiated transactions from January 1, 2014 through the end of 2017. The repurchase program does not obligate Wisconsin Energy to acquire any specific number of shares and may be suspended or terminated by the Board of Directors at any time.

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	WISCONSIN ENERGY CORP
Entity Central Index Key	0000783325
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 9.3
Entity Common Stock, Shares Outstanding (actual number of shares)		225,946,296

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Long-Term Debt and Capital Lease Obligations

12 Months Ended

Dec. 31, 2013

Long-term Debt and Capital Lease Obligations [Abstract]

LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

 LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

Debentures and Notes:   As of December 31, 2013, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:

	(Millions of Dollars)
2014	$	322.4
2015	399.5
2016	27.4
2017	29.5
2018	281.1
Thereafter	3,566.8
Total	$	4,626.7

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

Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2013 and 2012, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

In connection with our outstanding Junior Notes, we executed the Replacement Capital Covenant dated May 11, 2007 (RCC) for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.

Obligations Under Capital Leases:   In 1997, Wisconsin Electric 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, Wisconsin Electric may, at its option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and 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.

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $33.7 million and $32.5 million in lease payments during 2013 and 2012, respectively. 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 lease in Note C). Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $104.3 million as of December 31, 2013, and will decrease to zero over the remaining life of the contract.

The following is a summary of our capitalized leased facilities as of December 31:

Capital Lease Assets	2013			2012
	(Millions of Dollars)
Leased Facilities
Long-term power purchase commitment	$	140.3		$	140.3
Accumulated amortization	(92.5		)	(86.8		)
Total Leased Facilities	$	47.8		$	53.5

Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2013 are as follows:

	(Millions of Dollars)
2014	$	41.9
2015	43.5
2016	45.1
2017	13.9
2018	14.7
Thereafter	56.8
Total Minimum Lease Payments	215.9
Less:  Estimated Executory Costs	(61.7		)
Net Minimum Lease Payments	154.2
Less:  Interest	(49.9		)
Present Value of Net
Minimum Lease Payments	104.3
Less:  Due Currently	(19.8		)
	$	84.5

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Condensed Parent Company Financial Statements (Details 3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Parent Company long-term debt outstanding
Next year	$ 322.4
Year 2	399.5
Year 3	27.4
Year 4	29.5
Year 5	281.1
Thereafter	3,566.8
Total	4,626.7
Wisconsin Energy Corporation [Member]
Parent Company long-term debt outstanding
Next year	0
Year 2	0
Year 3	0
Year 4	0
Year 5	0
Thereafter	700.0
Total	$ 700.0

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets
Allowance on accounts receivable	$ 61.0	$ 58.0

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

REGULATORY ASSETS AND LIABILITIES

 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, 2013, we had $10.1 million of regulatory assets not earning a return and $82.7 million of regulatory assets earning a return based on short-term interest rates.

In December 2012, the PSCW issued a rate order effective January 1, 2013 that, among other things, reaffirmed our accounting for the regulatory assets and liabilities identified below.

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

	2013		2012
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	537.6	$	731.5
Deferred income tax related	169.5		176.5
Escrowed electric transmission costs	126.8		114.1
Escrowed conservation	66.9		73.5
Deferred plant related -- capital lease	56.5		66.6
Deferred environmental costs	47.0		47.4
Other, net	104.2		170.7
Total regulatory assets	$	1,108.5	$	1,380.3
Regulatory Liabilities
Deferred cost of removal obligations	$	724.5	$	725.0
Escrowed bad debt costs	64.6		81.1
Other, net	90.0		62.2
Total regulatory liabilities	$	879.1	$	868.3

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Recent Accounting Pronouncements

12 Months Ended

Dec. 31, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

RECENT ACCOUNTING PRONOUNCEMENTS

 RECENT ACCOUNTING PRONOUNCEMENTS

Offsetting Assets and Liabilities: In January 2013, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2013-01, Disclosures about Offsetting Assets and Liabilities. The guidance requires enhanced disclosures about derivatives. Both gross and net information related to eligible transactions is required under the guidance. This guidance is effective for fiscal years and interim periods beginning on or after January 1, 2013, and must be applied retrospectively. We adopted this guidance on January 1, 2013, and applied it retrospectively. The adoption and retrospective application of this guidance did not have any material impact on our financial statements. See Note L -- Derivative Instruments for the enhanced disclosures.

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Segment Reporting

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

SEGMENT REPORTING

SEGMENT REPORTING

Our reportable segments as of December 31, 2013 include a utility energy segment and a non-utility energy segment. We have organized our reportable segments based upon the regulatory environment in which our utility subsidiaries operate and on how management makes decisions and measures performance. The segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation 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 operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Summarized financial information concerning our reportable segments for each of the three years ended December 31, 2013 is shown in the following table.

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2013
Operating Revenues (b)	$	4,462.0	$	446.7	$	1.3		$	(391.0	)	$	4,519.0
Depreciation and Amortization	$	320.2	$	67.1	$	0.8		$	—		$	388.1
Operating Income (Loss)	$	719.4	$	367.1	$	(6.4	)	$	—		$	1,080.1
Equity in Earnings of Unconsolidated Affiliates	$	68.5	$	—	$	(0.1	)	$	—		$	68.4
Interest Expense, Net	$	136.2	$	65.7	$	50.8		$	(0.6	)	$	252.1
Income Tax Expense (Benefit)	$	243.6	$	120.2	$	(25.9	)	$	—		$	337.9
Net Income (Loss)	$	425.1	$	181.6	$	577.2		$	(606.5	)	$	577.4
Capital Expenditures	$	657.9	$	26.1	$	3.4		$	—		$	687.4
Total Assets (c)	$	14,460.4	$	2,846.5	$	4,719.5		$	(7,257.0	)	$	14,769.4

December 31, 2012
Operating Revenues (b)	$	4,190.8	$	439.9	$	1.2		$	(385.5	)	$	4,246.4
Depreciation and Amortization	$	296.4	$	67.1	$	0.7		$	—		$	364.2
Operating Income (Loss)	$	647.7	$	358.8	$	(6.2	)	$	—		$	1,000.3
Equity in Earnings of Unconsolidated Affiliates	$	65.7	$	—	$	(0.2	)	$	—		$	65.5
Interest Expense, Net	$	129.4	$	66.7	$	52.5		$	(0.4	)	$	248.2
Income Tax Expense (Benefit)	$	214.9	$	116.6	$	(25.2	)	$	—		$	306.3
Net Income (Loss)	$	400.6	$	175.9	$	546.1		$	(576.3	)	$	546.3
Capital Expenditures	$	697.3	$	5.5	$	4.2		$	—		$	707.0
Total Assets (c)	$	13,988.1	$	2,903.5	$	4,431.4		$	(7,038.0	)	$	14,285.0

December 31, 2011
Operating Revenues (b)	$	4,431.5	$	435.1	$	0.9		$	(381.1	)	$	4,486.4
Depreciation and Amortization	$	257.0	$	72.5	$	0.7		$	—		$	330.2
Operating Income (Loss)	$	544.8	$	348.9	$	(6.4	)	$	—		$	887.3
Equity in Earnings of Unconsolidated Affiliates	$	62.5	$	—	$	(0.9	)	$	—		$	61.6
Interest Expense, Net	$	110.0	$	66.7	$	59.5		$	(0.4	)	$	235.8
Income Tax Expense (Benefit)	$	182.7	$	112.8	$	(31.6	)	$	—		$	263.9
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	13.4		$	—		$	13.4
Net Income (Loss)	$	376.3	$	169.8	$	525.9		$	(545.8	)	$	526.2
Capital Expenditures	$	792.2	$	31.2	$	7.4		$	—		$	830.8
Total Assets (c)	$	13,433.5	$	2,949.0	$	4,694.8		$	(7,215.2	)	$	13,862.1

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

(c) An elimination of $2,231.2 million, $2,286.7 million and $2,369.0 million is included in Total Assets as of December 31, 2013, 2012 and 2011, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

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Short-Term Debt

12 Months Ended

Dec. 31, 2013

Short-term Debt [Abstract]

SHORT-TERM DEBT

SHORT-TERM DEBT

Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

	2013				2012
			Interest				Interest
Short-Term Debt	Balance		Rate		Balance		Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	537.4	0.20	%	$	394.6	0.30	%

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

	2013			2012
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$	594.5		$	669.9
Average Short-Term Debt Outstanding	$	359.1		$	481.6
Weighted-Average Interest Rate	0.25		%	0.28		%

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require the companies to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.

As of December 31, 2013, we had approximately $1.2 billion of available undrawn lines under our bank back-up credit facilities and $537.4 million of commercial paper outstanding that was supported by the available lines of credit. Our bank back-up credit facilities expire in December 2017.

The Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control. In addition, pursuant to the terms of Wisconsin Energy's credit agreement, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein.

As of December 31, 2013, we were in compliance with all financial covenants.

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Schedule I -- Condensed Parent Company Financial Statements Condensed Parent Company Financial Statements (Details 7) (Details) (Parent Company [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Parent Company [Member]
Subsequent Event [Line Items]
Special Dividend Paid from Wisconsin Electric to Parent Company	$ 50.0

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Variable Interest Entities

12 Months Ended

Dec. 31, 2013

Variable Interest Entities [Abstract]

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

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

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

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

We have approximately $215.9 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 2013, 2012 and 2011 were $50.3 million, $45.8 million and $65.9 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

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Common Equity (Details 4) (USD $)	1 Months Ended	12 Months Ended			1 Months Ended		32 Months Ended	12 Months Ended
	Jan. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Share Repurchase Plan, 2014 - 2017 [Member] [Domain]	May 31, 2011 Share Repurchase Plan, 2011 [Member]	Dec. 31, 2013 Share Repurchase Plan, 2011 [Member]	Dec. 31, 2013 Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]	Dec. 31, 2012 Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]	Dec. 31, 2011 Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]	Dec. 31, 2013 Share Repurchase Plan, 2011 [Member]	Dec. 31, 2012 Share Repurchase Plan, 2011 [Member]	Dec. 31, 2011 Share Repurchase Plan, 2011 [Member]	Dec. 31, 2013 Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock Repurchased During Period, Shares		5,400,000	4,300,000	6,200,000				2,400,000	2,800,000	3,000,000	3,000,000	1,500,000	3,200,000
Common Equity (Textuals)
Common stock shares, Authorized		325,000,000	325,000,000
Common stock shares, Outstanding		225,962,959	229,039,456
Stock options awarded under long-term incentive compensation														1,418,560
Exercise price of non qualified stock options	$ 41.03
Intrinsic value of options exercised		$ 44,500,000	$ 47,500,000	$ 36,100,000
Exercise price of the stock option on the grant date		no less than 100% of the common stock's fair market value
Mimimum period after grant that stock options can be exercised														6 months
Expiration of options from time of grant														10 years
Minimum percentage award based on performance unit		0.00
Maximum percentage award based on performance unit		1.75
Amount paid for Shares Purchased by agents from open market		223,400,000	153,200,000	193,900,000
Exercise of stock options		48,500,000	49,800,000	54,400,000
Maximum period to defer interest payments on the Junior Notes		We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.
Ability to declare common dividends limited to Percentage of Net Income by Wisconsin Electric		limited to 75% or 50%
Wisconsin Electric's common stock equity to total capitalization		is less than 25% and 20%
3.60% Serial Preferred Stock		3.60%
Maximum percentage of equity method investment		50.00%
Equity method investment		3,600,000,000
Percentage of equity method investment exceeding consolidated net assets		25.00%
Stock Repurchase Program, Authorized Amount					300,000,000	300,000,000
Stock Repurchased and Retired During Period, Shares							7,700,000
Treasury Stock Acquired, Average Cost Per Share							$ 36.19
Treasury Stock, Value, Acquired, Cost Method							277,800,000
Stock Repurchased During Period, Value		$ 223,400,000	$ 153,200,000	$ 193,900,000				$ 97,400,000	$ 101,400,000	$ 93,900,000	$ 126,000,000	$ 51,800,000	$ 100,000,000

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Asset Sales, Divestitures and Discontinued Operations

12 Months Ended

Dec. 31, 2013

Asset Sales Divestitures and Discontinued Operations [Abstract]

ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

The following table summarizes the net impacts of the discontinued operations on our earnings for the years ended December 31:

	2013		2012		2011
	(Millions of Dollars)
Income from Continuing Operations	$	577.4	$	546.3	$	512.8
Income from Discontinued other operations, net of tax (a)	—		—		13.4
Net Income	$	577.4	$	546.3	$	526.2

(a) Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

Edgewater Generating Unit 5:   On March 1, 2011, we sold our 25% interest in Edgewater Generating Unit 5 to WPL for our net book value, including working capital, of approximately $38 million. This transaction was treated as a sale of an asset.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

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 2013 and 2012:

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	44.3		$	55.5
Liabilities Settled	(4.4		)	(14.0		)
Accretion	2.4			2.8
Balance as of December 31	$	42.3		$	44.3

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES

 INCOME TAXES

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

Income Taxes	2013			2012			2011
	(Millions of Dollars)
Current tax expense (benefit)	$	25.2		$	13.1		$	(166.7	)
Deferred income taxes, net	313.8			294.4			434.8
Investment tax credit, net	(1.1		)	(1.2		)	(4.2		)
Total Income Tax Expense	$	337.9		$	306.3		$	263.9

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 as a result of the following:

	2013					2012					2011
				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	$	320.3		35.0	%	$	298.4		35.0	%	$	271.8		35.0	%
State income taxes net of federal tax benefit	49.0			5.3	%	43.3			5.1	%	40.1			5.2	%
Production tax credits	(16.7		)	(1.8	)%	(15.9		)	(1.9	)%	(8.7		)	(1.1	)%
Treasury Grant	(7.4		)	(0.8	)%	—			—	%	—			—	%
AFUDC - Equity	(6.4		)	(0.7	)%	(12.3		)	(1.4	)%	(20.8		)	(2.7	)%
Investment tax credit restored	(1.1		)	(0.1	)%	(1.2		)	(0.1	)%	(4.2		)	(0.5	)%
Domestic production activities deduction	—			—	%	(12.6		)	(1.5	)%	(12.6		)	(1.6	)%
Other, net	0.2			—	%	6.6			0.7	%	(1.7		)	(0.3	)%
Total Income Tax Expense	$	337.9		36.9	%	$	306.3		35.9	%	$	263.9		34.0	%

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	2013		2012
	(Millions of Dollars)
Current
Future federal tax benefits	$	309.7	$	59.0
Employee benefits and compensation	13.8		14.9
Other	56.0		81.1
Total Current Deferred Tax Assets	379.5		155.0
Non-current
Deferred revenues	237.0		250.0
Employee benefits and compensation	95.6		97.0
Future federal tax benefits	32.5		334.7
Property-related	28.2		28.3
Construction advances	18.3		22.2
Other	62.9		16.3
Total Non-Current Deferred Tax Assets	474.5		748.5
Total Deferred Tax Assets	$	854.0	$	903.5

Deferred Tax Liabilities	2013		2012
	(Millions of Dollars)
Current
Prepaid items	$	69.5	$	49.7
Total Current Deferred Tax Liabilities	69.5		49.7
Non-current
Property-related	2,574.4		2,339.4
Employee benefits and compensation	238.5		244.3
Investment in transmission affiliate	169.9		144.9
Deferred transmission costs	50.8		45.7
Other	74.9		91.2
Total Non-current Deferred Tax Liabilities	3,108.5		2,865.5
Total Deferred Tax Liabilities	$	3,178.0	$	2,915.2
Consolidated Balance Sheet Presentation	2013		2012
Current Deferred Tax Asset	$	310.0	$	105.3
Non-Current Deferred Tax Liability	$	2,634.0	$	2,117.0

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, 2013, we had approximately $810.3 million and $58.6 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of $283.6 million and $58.6 million, respectively. As of December 31, 2012, we had approximately $1,007.1 million and $41.2 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of $352.5 million and $41.2 million, respectively. The tax credit and net operating loss carryforwards begin to expire in 2029. 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:

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	11.3		$	11.1
Additions for tax positions of prior years	—			10.8
Reductions for tax positions of prior years	(2.9		)	(10.6		)
Balance as of December 31	$	8.4		$	11.3

The amount of unrecognized tax benefits as of December 31, 2013 and 2012 excludes deferred tax assets related to uncertainty in income taxes of $8.4 million and $10.2 million, respectively. As of December 31, 2013, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations. As of December 31, 2012, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $1.0 million.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2013, 2012 and 2011, we recognized approximately $0.2 million, $0.2 million and $0.7 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2013 and 2012, we recognized no penalties in the Consolidated Income Statements. For the year ended 2011, we recognized a benefit of $0.3 million in the Consolidated Income Statements related to a reduction of accrued penalties. We had approximately $0.4 million and $0.3 million of interest accrued and no penalties accrued on the Consolidated Balance Sheets as of December 31, 2013 and 2012, respectively.

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

Our primary tax jurisdictions include the United States and the state of Wisconsin. Currently, the tax years of 2011 through 2013 are subject to Federal examination, and the tax years 2009 through 2013 are subject to examination by the state of Wisconsin.

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Derivative Instruments (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]
Regulatory assets related to derivatives	$ 1,108.5	$ 1,380.3
Derivative [Member]
Regulatory Assets [Line Items]
Regulatory assets related to derivatives	$ 0.3	$ 7.6

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Valuation and Qualifying Accounts (Details) (Allowance for Doubtful Accounts [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts
Balance at Beginning of the Period	$ 58.0	$ 61.7	$ 58.1
Expense	49.4	47.7	85.8
Deferral	0.4	(4.0)	(35.9)
Net Write-offs	(46.8)	(47.4)	(46.3)
Balance at End of the Period	$ 61.0	$ 58.0	$ 61.7

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Derivative Instruments (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]
Collateral in margin accounts	$ 0	$ 2.9
Derivative Asset	11.8	19.2
Derivative Liability	0.3	1.9
Reclassification in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income as increase to interest Expense	252.1	248.2	235.8
Derviative Instrument by Counterparty, Gross Amount Recognized on Balance Sheet [Member]
Derivative [Line Items]
Derivative Asset	11.8	19.2
Derivative Liability	0.3	1.9
Derviative Instrument by Counterparty, Gross Amount Not Offset on Balance Sheet [Member] [Member]
Derivative [Line Items]
Collateral in margin accounts	0	1.3
Derivative Asset	0	(0.5)
Derivative Liability	0	(1.8)
Derviative Instrument by Counterparty, Net Amount [Member]
Derivative [Line Items]
Derivative Asset	11.8	18.7
Derivative Liability	$ 0.3	$ 0.1

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Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivatives Fair Value [Line Items]
Derivative, Asset	$ 11.8	$ 19.2
Derivative, Liability	0.3	1.9
Gains (losses)	6.9	(28.4)
Other Deferred Charges and Other Assets [Member]
Derivatives Fair Value [Line Items]
Long-term portion of derivative assets	0.4
Other Long-Term Liabilities [Member]
Derivatives Fair Value [Line Items]
Long-term portion of derivative liabilities	0
Natural Gas [Member]
Derivatives Fair Value [Line Items]
Derivative, Asset	5.6	3.0
Derivative, Liability	0.1	1.9
Volume	48.6 million Dth	77.2 million Dth
Gains (losses)	(8.5)	(36.3)
Fuel Oil [Member]
Derivatives Fair Value [Line Items]
Derivative, Asset	0.6	0.4
Derivative, Liability	0	0
Volume	8.6 million gallons	7.0 million gallons
Gains (losses)	0.5	1.8
FTRs [Member]
Derivatives Fair Value [Line Items]
Derivative, Asset	3.5	4.7
Derivative, Liability	0	0
Volume	25.3 million MWh	25.1 million MWh
Gains (losses)	14.9	6.1
Coal [Member]
Derivatives Fair Value [Line Items]
Derivative, Asset	2.1	11.1
Derivative, Liability	$ 0.2	$ 0

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligations (Tables) [Abstract]

Change in Asset Retirement Obligations

The following table presents the change in our AROs during 2013 and 2012:

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	44.3		$	55.5
Liabilities Settled	(4.4		)	(14.0		)
Accretion	2.4			2.8
Balance as of December 31	$	42.3		$	44.3

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Regulatory Assets and Liabilities (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 879.1	$ 868.3
Deferred cost of removal obligations [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	724.5	725.0
Escrowed Bad Debt Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	64.6	81.1
Other, net [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 90.0	$ 62.2

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

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 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, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	5.7	$	2.6	$	3.5	11.8
Total	$	5.7	$	2.6	$	3.5	$	11.8
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

Recurring Fair Value Measures	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	2.7	$	—	$	—	$	2.7
Derivatives	2.2		12.3		4.7		19.2
Total	$	4.9	$	12.3	$	4.7	$	21.9
Liabilities:
Derivatives	$	1.9	$	—	$	—	$	1.9
Total	$	1.9	$	—	$	—	$	1.9

We adopted ASU 2013-01, Disclosures about Offsetting Assets and Liabilities, on a retrospective basis. For additional information, see Note B -- Recent Accounting Pronouncements and Note L -- Derivative Instruments.

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

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

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	4.7		$	5.7
Realized and unrealized gains (losses)	—			—
Purchases	10.6			11.0
Issuances	—			—
Settlements	(11.8		)	(12.0		)
Transfers in and/or out of Level 3	—			—
Balance as of December 31	$	3.5		$	4.7
Change in unrealized gains (losses) relating to instruments still held as of December 31	$	—		$	—

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:

	2013				2012
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	26.0	$	30.4	$	26.0
Long-term debt including current portion	$	4,626.7	$	4,911.8	$	4,772.9	$	5,447.3

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.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2013

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2013, we paid $250.4 million in interest, net of amounts capitalized, and received $39.6 million in net refunds from income taxes. During the year ended December 31, 2012, we paid $241.2 million in interest, net of amounts capitalized, and received $107.0 million in net refunds from income taxes. During the year ended December 31, 2011, we paid $234.0 million in interest, net of amounts capitalized, and received $109.1 million in net refunds from income taxes.

As of December 31, 2013, 2012 and 2011, the amount of accounts payable related to capital expenditures was $4.7 million, $15.7 million and $16.7 million, respectively.

During the years ended December 31, 2013, 2012 and 2011, total amortization of deferred revenue was $56.5 million, $54.9 million and $54.4 million, respectively.

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Summary of Significant Accounting Policies (Details 3) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Debt Securities In Cash Equivalents, Maximum Period Until Maturity	0 years 3 months
Fuel Cost Tolerance Range Set by Regulators, Percent	2.00%
Regulatory liabilities	$ 879.1	$ 868.3
Fair value of stock options
Dividend yield	3.70%	3.90%	3.90%
Expected volatility	18.00%	19.00%	19.00%
Expected life (years)	5 years 11 months	5 years 11 months	5 years 6 months
Expected forfeiture rate	2.00%	2.00%	2.00%
Weighted average fair value of our stock options granted	$ 3.45	$ 3.34	$ 3.17
Other Income and Deductions, Net
AFUDC - Equity	18.3	35.3	59.4
Other, net	0.5	(0.5)	3.3
Other Income and Deductions, net	18.8	34.8	62.7
Allowance For Funds Used During Construction
AFUDC - Debt	7.7	14.7	24.7
AFUDC - Equity	18.3	35.3	59.4
Inventories
Fossil Fuel	117.7	165.5
Materials and Supplies	133.9	121.9
Natural Gas in Storage	77.8	73.3
Total	329.4	360.7
Summary Of Significant Accounting Policies (Additional) (Textuals) [Abstract]
Symmetrical Fuel Cost Tolerance Range Set By Regulatory Authority	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.
Reclassification of deferred tax assets	59.0
Depreciation percentage of average depreciable utility plant	2.90%	2.90%	2.80%
Maximum duration to recover outstanding regulatory assets	8 years
Minimum duration to recover outstanding regulatory assets	1 year
Impairment charges related to goodwill	0
Long-lived assets held for sale	0
Revenue from Grants	48.0	0	0
Grants Receivable, Current	$ 82.6
Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration of options from time of grant	10 years
Fair value of stock options
Weighted average fair value of our stock options granted	$ 37.46

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Benefits (Tables)

12 Months Ended

Dec. 31, 2013

Benefits (Tables) [Abstract]

Details about pension and OPEB plans

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

	Pension						OPEB
	2013			2012			2013			2012
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,508.5		$	1,330.6		$	381.2		$	389.7
Service cost	14.6			21.7			10.0			10.3
Interest cost	60.4			65.5			15.6			20.3
Participants' contributions	—			—			8.9			9.6
Plan amendments	(1.0		)	—			—			0.5
Actuarial loss (gain)	(81.9		)	166.5			(27.7		)	(23.8		)
Other accrued benefits	—			31.4			—			—
Gross benefits paid	(90.4		)	(107.2		)	(26.3		)	(26.3		)
Federal subsidy on benefits paid	N/A			N/A			1.0			0.9
Benefit Obligation at December 31	$	1,410.2		$	1,508.5		$	362.7		$	381.2
Change in Plan Assets
Fair Value at January 1	$	1,385.4		$	1,262.5		$	285.4		$	255.4
Actual earnings on plan assets	147.3			127.4			45.5			29.0
Employer contributions	8.7			102.7			14.1			17.7
Participants' contributions	—			—			8.9			9.6
Gross benefits paid	(90.4		)	(107.2		)	(26.3		)	(26.3		)
Fair Value at December 31	$	1,451.0		$	1,385.4		$	327.6		$	285.4
Net asset (liability)	$	40.8		$	(123.1	)	$	(35.1	)	$	(95.8	)

Amounts recognized in Consolidated Balance Sheets

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

	Pension				OPEB
	2013		2012		2013		2012
	(Millions of Dollars)
Other long-term assets	$	138.7	$	—	$	40.2	$	25.1
Other long-term liabilities	$	97.9	$	123.1	$	75.3	$	120.9

Amounts not yet been recognized in net periodic benefit cost

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
	2013		2012		2013			2012
	(Millions of Dollars)
Net actuarial loss	$	528.8	$	719.2	$	9.8		$	65.3
Prior service costs (credits)	8.8		12.2		(1.7		)	(3.7		)
Total - Regulatory Assets	$	537.6	$	731.4	$	8.1		$	61.6

Components of net periodic pension and OPEB costs

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

	Pension									OPEB
	2013			2012			2011			2013			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	14.6		$	21.7		$	15.9		$	10.0		$	10.3		$	10.4
Interest cost	60.4			65.5			67.6			15.6			20.3			20.8
Expected return on plan assets	(95.8		)	(89.6		)	(82.1		)	(21.3		)	(19.0		)	(16.9		)
Amortization of:
Transition obligation	—			—			—			—			0.3			0.3
Prior service cost (credit)	2.3			2.2			2.2			(2.0		)	(1.9		)	(1.9		)
Actuarial loss	54.5			41.0			34.0			3.7			7.3			6.2
Settlement charge	2.5			—			—			—			—			—
Other	—			0.4			—			—			—			—
Net Periodic Benefit Cost	$	38.5		$	41.2		$	37.6		$	6.0		$	17.3		$	18.9

	Pension			OPEB
	2013	2012	2011	2013	2012	2011
Weighted-Average assumptions used to
determine benefit obligations as of Dec. 31
Discount rate	5.00%	4.10%	5.05%	4.95%	4.15%	5.20%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A
Weighted-Average assumptions used to
determine net cost for year ended Dec. 31
Discount rate	4.10%	5.05%	5.60%	4.15%	5.20%	5.70%
Expected return on plan assets	7.25%	7.25%	7.25%	7.50%	7.50%	7.50%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A

Assumed health care cost trend rates as of Dec. 31	2013	2012	2011
Health care cost trend rate assumed for next year (Pre 65 / Post 65)	7.5%/7.5%	7.5%/7.5%	8.0%/12%
Rate that the cost trend rate gradually adjusts to	5.0%	5.0%	5.0%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)	2021/2021	2017/2017	2017/2017

The expecte

A one-percentage-point change in assumed health care cost trend rates effects

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	$	26.4	$	(22.3	)
Total of service and interest cost components	$	3.2	$	(2.6	)

Summary of fair value of plan assets by asset category within fair value hierarchy

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

	As of December 31, 2013
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	21.0	$	—	$	—	$	21.0
Equities:
U.S. Equity	519.5		—		—		519.5
International Equity	146.2		35.7		—		181.9
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	108.4		505.2		—		613.6
International Bonds	78.1		36.9		—		115.0
Total	$	873.2	$	577.8	$	—	$	1,451.0

	As of December 31, 2012
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	13.7	$	—	$	—	$	13.7
Equities:
U.S. Equity	466.3		—		—		466.3
International Equity	134.7		30.4		—		165.1
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	67.7		546.6		—		614.3
International Bonds	80.7		45.3		—		126.0
Total	$	763.1	$	622.3	$	—	$	1,385.4

(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 OPEB plan assets by asset category within the fair value hierarchy:

	As of December 31, 2013
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	2.6	$	—	$	—	$	2.6
Equities:
U.S. Equity	148.0		—		—		148.0
International Equity	46.9		2.8		—		49.7
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	8.4		96.3		—		104.7
International Bonds	16.8		5.8		—		22.6
Total	$	222.7	$	104.9	$	—	$	327.6

	As of December 31, 2012
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	1.7	$	—	$	—	$	1.7
Equities:
U.S. Equity	125.9		—		—		125.9
International Equity	39.9		2.2		—		42.1
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	5.0		89.9		—		94.9
International Bonds	15.4		5.4		—		20.8
Total	$	187.9	$	97.5	$	—	$	285.4

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

Employer contributions to defined benefit plan

Cash Flows:   

Historical employer contributions:

	Pension
Year	Qualified		Non-Qualified		OPEB
	(Millions of Dollars)
2011	$	236.4	$	6.5	$	48.4
2012	$	95.6	$	7.1	$	17.7
2013	$	—	$	8.7	$	14.1

Expected benefit payments in future

Estimated benefit payments:

Year	Pension		Gross OPEB
	(Millions of Dollars)
2014	$	103.9	$	24.2
2015	$	98.6	$	21.6
2016	$	100.3	$	22.0
2017	$	100.9	$	22.6
2018	$	100.2	$	23.4
2019-2023	$	495.6	$	119.7

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities
Net income	$ 577.4	$ 546.3	$ 526.2
Reconciliation to cash
Depreciation and amortization	400.2	371.7	336.4
Deferred income taxes and investment tax credits, net	312.7	293.2	430.6
Contributions to qualified benefit plans	0	(100.0)	(277.4)
Change in -
Accounts receivable and accrued revenues	(162.9)	38.3	30.1
Inventories	31.3	21.3	(2.9)
Other current assets	2.8	12.1	(20.5)
Accounts payable	(14.8)	43.8	11.8
Accrued income taxes, net	36.6	116.9	(87.4)
Deferred costs, net	(8.7)	9.2	25.9
Other current liabilities	7.2	(14.9)	44.1
Other, net	49.2	(164.0)	(23.5)
Cash Provided by Operating Activities	1,231.0	1,173.9	993.4
Investing Activities
Capital expenditures	(687.4)	(707.0)	(830.8)
Investment in transmission affiliate	(10.5)	(15.7)	(6.6)
Proceeds from asset sales	2.5	8.7	41.5
Change in restricted cash	2.7	42.8	(37.2)
Payments for (Proceeds from) Removal Costs	(37.8)	(38.3)	(16.9)
Other, net	(15.3)	(20.1)	(42.5)
Cash Used in Investing Activities	(745.8)	(729.6)	(892.5)
Financing Activities
Exercise of stock options	48.5	49.8	54.4
Purchase of common stock	(223.4)	(153.2)	(193.9)
Dividends paid on common stock	(328.9)	(276.3)	(242.0)
Issuance of long-term debt	251.0	251.8	720.0
Retirement and repurchase of long-term debt	(397.2)	(20.3)	(466.6)
Change in short-term debt	142.8	(275.3)	12.0
Other, net	12.4	0.7	4.8
Cash Used in Financing Activities	(494.8)	(422.8)	(111.3)
Change in Cash and Cash Equivalents	(9.6)	21.5	(10.4)
Cash and Cash Equivalents at Beginning of Year	35.6	14.1	24.5
Cash and Cash Equivalents at End of Year	$ 26.0	$ 35.6	$ 14.1

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our subsidiaries in the following reportable segments:

• Utility Energy Segment -- Consisting of Wisconsin Electric and Wisconsin Gas, engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and

• Non-Utility Energy Segment -- Consisting primarily of We Power, engaged principally in the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Our Corporate and Other segment includes Wispark, which develops and invests in real estate. We have also eliminated all intercompany transactions 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.

Reclassifications and Adjustments:As of December 31, 2013, we have presented the tax effect of net operating loss carryforwards within current deferred tax assets, net on the consolidated balance sheets. As of December 31, 2012, $59.0 million representing the tax effect of net operating loss carryforwards were included in income taxes receivable, which is a line item that has now been condensed within other current assets on the consolidated balance sheets. This $59.0 million amount has been adjusted in the consolidated balance sheets as of December 31, 2012 to conform to the December 31, 2013 presentation, and conforming changes have been made in the consolidated statements of cash flows and in the notes to the consolidated financial statements. For additional information related to our deferred tax assets, see Note G.

In addition, we have adjusted the presentation of regulatory assets and liabilities to present amounts as noncurrent assets and liabilities on the consolidated balance sheets. Prior period amounts recorded within other current assets and liabilities have been reclassified to conform to the current presentation. For additional information related to regulatory assets and liabilities, see Note C.

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.

We recognize We Power revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease.

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	2013		2012			2011
	(Millions of Dollars)
AFUDC - Equity	$	18.3	$	35.3		$	59.4
Other, net	0.5		(0.5		)	3.3
Total Other Income and Deductions, net	$	18.8	$	34.8		$	62.7

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.

We recorded the following property in service by segment as of December 31:

Property In Service	2013		2012
	(Millions of Dollars)
Utility Energy	$	11,779.8	$	11,080.9
Non-Utility Energy	3,091.3		3,068.5
Other	95.2		89.4
Total	$	14,966.3	$	14,238.8

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 2013 and 2012, and 2.8% in 2011.

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.

Our regulated utilities collect in their 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 $724.5 million as of December 31, 2013 and $725.0 million as of December 31, 2012.

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2013		2012
	(Millions of Dollars)
Utility Energy	$	132.7	$	298.2
Non-Utility Energy	16.5		13.3
Other	0.4		4.4
Total	$	149.6	$	315.9

Allowance For Funds Used During Construction - Regulated:   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.

Our regulated utility segment recorded the following AFUDC for the years ended December 31:

	2013		2012		2011
	(Millions of Dollars)
AFUDC - Debt	$	7.7	$	14.7	$	24.7
AFUDC - Equity	$	18.3	$	35.3	$	59.4

Capitalized Interest and Carrying Costs - Non-Regulated Energy:   As part of the construction of the PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheet and we are amortizing the deferred carrying costs to revenue over the individual lease terms.

Earnings per Common Share:   We compute basic earnings per common share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. All stock options outstanding during 2013, 2012 and 2011 were included in the computation of diluted earnings per share. Anti-dilutive shares are excluded from the calculation.

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

Materials, Supplies and Inventories	2013		2012
	(Millions of Dollars)
Fossil Fuel	$	117.7	$	165.5
Materials and Supplies	133.9		121.9
Natural Gas in Storage	77.8		73.3
Total	$	329.4	$	360.7

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.

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.

Goodwill:   Goodwill reflects the cost of an acquisition in excess of the fair values assigned to identifiable net assets acquired. As of December 31, 2013 and 2012, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.

Goodwill is not subject to amortization. However, it is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. Fair value is assessed by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2013 impairment test date.

Impairment or Disposal of Long Lived Assets:   We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2013, 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 26.2% in ATC as of December 31, 2013 and 2012. 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. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note G.

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:   We estimate the fair value of stock options using the binomial pricing model. We report unearned stock-based compensation associated with non-vested restricted stock and performance share awards activity within Other Paid in Capital in our Consolidated Statements of Common Equity. We report excess tax benefits as a financing cash inflow. 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 grant date. For a discussion of the impacts to our Consolidated Financial Statements, see Note H.

The fair value of our stock options was calculated using a binomial option-pricing model using the following weighted-average assumptions:

	2013	2012	2011
Risk-free interest rate	0.1% - 1.9%	0.1% - 2.0%	0.2% - 3.4%
Dividend yield	3.7%	3.9%	3.9%
Expected volatility	18.0%	19.0%	19.0%
Expected life (years)	5.9	5.9	5.5
Expected forfeiture rate	2.0%	2.0%	2.0%
Weighted-average fair value
of our stock options granted	$3.45	$3.34	$3.17

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 this will continue into 2014. As of December 31, 2013, $48.0 million was recognized as income, which reflects the amount that was returned to customers in the form of bill credits during the year. We recorded an $82.6 million receivable, and deferred the balance that we expect to benefit our customers in the future. The accounting reflects the regulatory treatment of the grant.

The PSCW approved escrow accounting treatment for the Treasury Grant. Under escrow accounting, we true-up any differences between the actual grant proceeds received and the grant proceeds passed on to customers in the form of bill credits.

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Common Equity (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013
Stock options outstanding
Options Outstanding, Number, Total	8,089,710
Options Outstanding, Weighted-Average Exercise Price	$ 26.84
Options Outstanding, Weighted-Average Remaining Contractual Life (Years)	5 years 5 months
Options Exercisable, Number, Total	5,708,920
Options Exercisable, Weighted-Average Exercise Price	$ 23.16
Options Exercisable, Weighted-Average Remaining Contractual Life (Years)	4 years 1 month
Exercise Price, Range One [Member]
Stock options outstanding
Options Outstanding, Number, Total	2,128,370
Options Outstanding, Weighted-Average Exercise Price	$ 20.34
Options Outstanding, Weighted-Average Remaining Contractual Life (Years)	3 years 11 months
Options Exercisable, Number, Total	2,128,370
Options Exercisable, Weighted-Average Exercise Price	$ 20.34
Options Exercisable, Weighted-Average Remaining Contractual Life (Years)	3 years 11 months
Exercise Price, Range One [Member] | Maximum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 21.11
Exercise Price, Range One [Member] | Minimum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 16.72
Exercise Price, Range Two [Member]
Stock options outstanding
Options Outstanding, Number, Total	3,689,900
Options Outstanding, Weighted-Average Exercise Price	$ 24.65
Options Outstanding, Weighted-Average Remaining Contractual Life (Years)	4 years 2 months
Options Exercisable, Number, Total	3,382,630
Options Exercisable, Weighted-Average Exercise Price	$ 24.23
Options Exercisable, Weighted-Average Remaining Contractual Life (Years)	4 years 0 months
Exercise Price, Range Two [Member] | Maximum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 29.35
Exercise Price, Range Two [Member] | Minimum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 23.88
Exercise Price, Range Three [Member]
Stock options outstanding
Options Outstanding, Number, Total	2,271,440
Options Outstanding, Weighted-Average Exercise Price	$ 36.48
Options Outstanding, Weighted-Average Remaining Contractual Life (Years)	8 years 7 months
Options Exercisable, Number, Total	197,920
Options Exercisable, Weighted-Average Exercise Price	$ 35.19
Options Exercisable, Weighted-Average Remaining Contractual Life (Years)	8 years 1 month
Exercise Price, Range Three [Member] | Maximum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 37.46
Exercise Price, Range Three [Member] | Minimum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 34.88

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Condensed Parent Company Financial Statements (Details 5) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Issuance of new notes and the proceeds used to repay short-term debt	$ 397.2	$ 20.3	$ 466.6
Issuance of Junior Notes	251.0	251.8	720.0
Restriction under RCC	The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.
Interest paid, net of amounts capitalized	250.4	241.2	234.0
Net refunds from income taxes	39.6	107.0	109.1
Wisconsin Energy Corporation [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Long-term notes outstanding of WECC	50
Issuance of new notes and the proceeds used to repay short-term debt	0	0	450.0
Minimum Total Funded Debt to Capitalization Ratio, As a Percent	70.00%
Interest paid, net of amounts capitalized	44.4	45.2	57.7
Net refunds from income taxes	86.1	128.2	114.6
Wisconsin Electric and Wisconsin Gas [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Dividends and distributions from subsidiaries	373.0
We Power [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Dividends and distributions from subsidiaries	$ 347.4
Notes (unsecured), 6.20% due 2033 [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate	6.20%	6.20%
Junior Notes (unsecured), 6.25% due 2067 [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate	6.25%	6.25%

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Financial Instruments
Preferred Stock	$ 30.4	$ 30.4
Long-term debt including current portion, carrying value	4,626.7	4,772.9
Long-term debt including current portion, fair value	4,911.8	5,447.3
Fair Value [Member]
Financial Instruments
Preferred Stock	26.0	26.0
Carrying Amount [Member]
Financial Instruments
Preferred Stock	$ 30.4	$ 30.4

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Schedule I -- Condensed Parent Company Financial Statements

12 Months Ended

Dec. 31, 2013

Schedule I -- Condensed Parent Company Financial Statements [Abstract]

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

WISCONSIN ENERGY CORPORATION

INCOME STATEMENTS

(Parent Company Only)

SCHEDULE I -- CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS

	Year Ended December 31
	2013			2012			2011
	(Millions of Dollars)
Other Income, Net	$	3.1		$	3.2		$	2.7
Corporate Expense	5.5			4.8			4.8
Interest Expense	54.4			55.7			61.8
Loss before Taxes	(56.8		)	(57.3		)	(63.9		)
Income Tax Benefit	26.4			26.0			30.8
Loss after Taxes	(30.4		)	(31.3		)	(33.1		)
Equity in Subsidiaries' Continuing Operations	607.8			577.6			545.9
Income from Continuing Operations	577.4			546.3			512.8
Income from Discontinued Operations including Equity in Subsidiaries' Discontinued Operations	—			—			13.4
Net Income	$	577.4		$	546.3		$	526.2
See accompanying notes to condensed parent company financial statements.

WISCONSIN ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

	Year Ended December 31
	2013			2012			2011
	(Millions of Dollars)
Operating Activities
Net income	$	577.4		$	546.3		$	526.2
Reconciliation to cash
Equity in subsidiaries' earnings	(607.8		)	(577.6		)	(545.9		)
Dividends and distributions from subsidiaries	720.4			842.3			995.5
Deferred income taxes, net	(7.8		)	104.4			(350.9		)
Accrued income taxes, net	66.8			(457.9		)	363.4
Change in - Other current assets	(0.1		)	0.2			(0.1		)
Change in - Other current liabilities	(22.9		)	(6.7		)	8.9
Change in - Accounts receivable	(2.7		)	22.5			(18.7		)
Other, net	(21.6		)	(8.1		)	(10.2		)
Cash Provided by Operating Activities	701.7			465.4			968.2
Investing Activities
Capital contributions to associated companies	(195.3		)	(21.5		)	(36.5		)
Capitalized interest and other	4.0			12.6			2.4
Cash Used in Investing Activities	(191.3		)	(8.9		)	(34.1		)
Financing Activities
Exercise of stock options	48.5			49.8			54.4
Purchase of common stock	(223.4		)	(153.9		)	(193.9		)
Dividends paid on common stock	(328.9		)	(276.3		)	(242.0		)
Retirement of long-term debt	—			—			(450.0		)
Change in short-term debt	5.0			(79.5		)	(116.5		)
Change in notes payable due associated companies	(26.8		)	3.8			3.9
Other, net	14.6			—			9.9
Cash Used in Financing Activities	(511.0		)	(456.1		)	(934.2		)
Change in Cash and Cash Equivalents	(0.6		)	0.4			(0.1		)
Cash and Cash Equivalents at Beginning of Year	0.9			0.5			0.6
Cash and Cash Equivalents at End of Year	$	0.3		$	0.9		$	0.5
See accompanying notes to condensed parent company financial statements.

WISCONSIN ENERGY CORPORATION

BALANCE SHEETS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

	December 31
	2013		2012
	(Millions of Dollars)
Assets
Current Assets
Cash and cash equivalents	$	0.3	$	0.9
Accounts and notes receivable from associated companies	37.4		32.9
Prepaid taxes and other	297.6		176.3
Total Current Assets	335.3		210.1
Property and Investments
Investment in subsidiary companies	4,761.8		4,662.3
Other	1.8		2.1
Total Property and Investments	4,763.6		4,664.4
Deferred Charges and Other Assets	143.2		331.4
Total Assets	$	5,242.1	$	5,205.9
Liabilities and Equity
Current Liabilities
Short-term debt	$	72.0	$	67.0
Notes payable due associated companies	113.8		140.6
Accrued taxes and other	11.8		34.7
Total Current Liabilities	197.6		242.3
Long-term debt	695.0		694.3
Other Long-term liabilities	116.5		134.2
Stockholder's equity	4,233.0		4,135.1
Total Liabilities and Equity	$	5,242.1	$	5,205.9
See accompanying notes to condensed parent company financial statements.

WISCONSIN ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

1.    For Parent Company only presentation, investment in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Wisconsin Energy Corporation appearing in this Annual Report on Form 10-K.

2.    Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from the Parent Company's non-utility subsidiary, We Power, and its principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. During 2013, Wisconsin Electric and Wisconsin Gas collectively provided Wisconsin Energy with $373.0 million of dividends, and We Power provided $347.4 million of distributions.

Various financing arrangements and regulatory requirements impose certain restrictions on the ability of the Parent Company's subsidiaries to transfer funds to the Parent Company in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to the Parent Company.

Wisconsin Energy does not believe that these restrictions will materially affect the Parent Company's operations or limit any dividend payments in the foreseeable future.

3.    As of December 31, 2013, the maturities of the Parent Company long-term debt outstanding were as follows:

	(Millions of Dollars)
2014	$	—
2015	—
2016	—
2017	—
2018	—
Thereafter	700.0
Total	$	700.0

Wisconsin Energy amortizes debt premiums, discounts and debt issuance costs over the lives of the debt and includes the costs in interest expense.

Wisconsin Energy entered into a new bank back-up credit facility in December 2012. The facility contains customary covenants, including certain limitations on Wisconsin Energy's 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, ERISA defaults and change of control. In addition, pursuant to the terms of the credit facility, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein. In addition, Wisconsin Energy is required to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%.

As of December 31, 2013, Wisconsin Energy was in compliance with all covenants.

WECC is a subsidiary of Wisconsin Energy and has $50 million of long-term notes outstanding. In a Support Agreement between WECC and Wisconsin Energy, Wisconsin Energy agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due.

4.    Wisconsin Energy and certain of its subsidiaries enter into various guarantees to provide financial and performance assurance to third parties on behalf of affiliates. As of December 31, 2013, Wisconsin Energy had the following guarantees which are eliminated upon consolidation and not included in the Wisconsin Energy Notes to Consolidated Statements:

	Maximum				Liability
	Potential		Outstanding		Recorded
	Future		as of		as of
	Payments		Dec 31, 2013		Dec 31, 2013
	(Millions of Dollars)
Wisconsin Energy Guarantees
Utility	$	3.8	$	3.8	$	—
Non-Utility Energy	55.5		—		—
Other	0.3		—		—
Total	$	59.6	$	3.8	$	—
Letters of Credit	$	0.1	$	0.1	$	—

Utility guarantees support obligations of the utility segment under surety bonds, worker's compensation and agreements.

Wisconsin Energy's guarantees in support of its non-utility energy segment guaranty performance and payment obligations of We Power. The guarantees which support We Power are for obligations under purchase, construction and lease agreements with the utility segment and third parties.

Wisconsin Energy has a guarantee that supports an environmental indemnification obligation, which is unlimited, associated with the Minergy Neenah plant and indemnifications related to the post-closing obligations under the Minergy Neenah sale agreement which was entered into in September 2006. In the event the guarantee fails to perform, Wisconsin Energy would be responsible for the obligations.

5.    The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2013				2012
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Long-term debt including current portion	$	700.0	$	749.4	$	700.0	$	805.9

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 long-term debt, including the current portion of long-term debt, 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 Parent Company's bond rating and the present value of future cash flows.

6.    During the year ended December 31, 2013, Wisconsin Energy paid $44.4 million in interest, net of amounts capitalized, and received $86.1 million in refunds from income taxes. During the year ended December 31, 2012, Wisconsin Energy paid $45.2 million in interest, net of amounts capitalized, and received $128.2 million in refunds from income taxes. During the year ended December 31, 2011, Wisconsin Energy paid $57.7 million in interest, net of amounts capitalized, and received $114.6 million in refunds from income taxes.

Subsequent Event: On January 16, 2014, Wisconsin Electric's board of directors declared a special dividend of $50.0 million which was paid to Wisconsin Energy on January 30, 2014.

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Related Parties (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Income (Loss) from Equity Method Investments	$ 68.4	$ 65.5	$ 61.6
American Transmission Company [Member]
Provided and received services from the associated companies
Services Received, -ATC	234.2	222.7	219.2
Receivable and payable balances with ATC
Services Received, -ATC	19.5	18.6
Related Parties (Textuals) [Abstract]
Equity interest in ATC	26.20%
Services [Member] | American Transmission Company [Member]
Provided and received services from the associated companies
Services Provided, -ATC	9.0	8.2	10.8
Receivable and payable balances with ATC
Services Provided, -ATC	0.6	0.5
Transmission Affiliate [Member]
Related Party Transaction [Line Items]
Income (Loss) from Equity Method Investments	68.5	65.7	62.5
Distributions from transmission affiliate	$ 54.5	$ 52.6	$ 49.7

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Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Short-Term Debt (Tables) [Abstract]

Short-term notes payable balances and their corresponding weighted-average interest rates

Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

	2013				2012
			Interest				Interest
Short-Term Debt	Balance		Rate		Balance		Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	537.4	0.20	%	$	394.6	0.30	%

Commercial paper

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

	2013			2012
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$	594.5		$	669.9
Average Short-Term Debt Outstanding	$	359.1		$	481.6
Weighted-Average Interest Rate	0.25		%	0.28		%

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Derivative Instruments

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedges, Assets [Abstract]

DERIVATIVE INSTRUMENTS

 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 and shareholders. 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, 2013, we recognized $0.3 million in regulatory assets and $9.6 million in regulatory liabilities related to derivatives in comparison to $7.6 million in regulatory assets and $17.5 million in regulatory liabilities as of December 31, 2012.

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 $0.4 million is recorded in other deferred charges and other assets, and we had no long-term portion of derivative liabilities. Our Consolidated Balance Sheets as of December 31, 2013 and 2012 include:

	December 31, 2013				December 31, 2012
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	5.6	$	0.1	$	3.0	$	1.9
Fuel Oil	0.6		—		0.4		—
FTRs	3.5		—		4.7		—
Coal	2.1		0.2		11.1		—
Total	$	11.8	$	0.3	$	19.2	$	1.9

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 were as follows:

	2013				2012
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	48.6 million Dth	$	(8.5	)	77.2 million Dth	$	(36.3	)
Fuel Oil	8.6 million gallons	0.5			7.0 million gallons	1.8
FTRs	25.3 million MWh	14.9			25.1 million MWh	6.1
Total		$	6.9			$	(28.4	)

As of December 31, 2013 and 2012, we posted collateral of zero and $2.9 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

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

	2013				2012
	Derivative		Derivative		Derivative			Derivative
	Asset		Liability		Asset			Liability
	(Millions of Dollars)
Gross Amount Recognized on the Balance Sheet	$	11.8	$	0.3	$	19.2		$	1.9
Gross Amount Not Offset on Balance Sheet (a)	—		—		(0.5		)	(1.8		)
Net Amount	$	11.8	$	0.3	$	18.7		$	0.1

(a) Gross Amount Not Offset on Balance Sheet includes cash collateral posted of zero and $1.3 million as of December 31, 2013 and 2012, respectively.