UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.Washington, D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
(Mark One)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended fiscal year ended December 31, 20122015

OR
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ___________________

Commission
File Number
Registrant; State of Incorporation;
Address; and Telephone Number
IRS Employer
Identification No.
001-01245WISCONSIN ELECTRIC POWER COMPANY39-0476280
(A Wisconsin Corporation)
231 West Michigan Street
P. O. Box 2046
Milwaukee, WI 53201
414-221-2345

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:
CommissionRegistrant; State of IncorporationIRS Employer
File NumberAddress; and Telephone NumberIdentification No.
001-01245WISCONSIN ELECTRIC POWER COMPANY39-0476280
(A Wisconsin Corporation)
231 West Michigan Street
P.O. Box 2046
Milwaukee, WI 53201
(414) 221-2345

Securities Registered Pursuant to Section 12(b) of the Act:    None
Securities Registered Pursuant to Section 12(g) of the Act:
Serial Preferred Stock, 3.60% Series, $100 Par Value
Six Per Cent. Preferred Stock, $100 Par Value

Indicate by check mark if the registrantRegistrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes [X]    No [ ]    No [X]

Indicate by check mark if the registrantRegistrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes [ ]    No [X]

Indicate by check mark whether the registrantRegistrant (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 registrantRegistrant 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,website, 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)chapter) is not contained herein, and will not be contained, to the best of registrant'sRegistrant'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 registrantRegistrant 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"filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

                                 Large accelerated filer [ ]                                 Accelerated filer [  ]
                                 Non-accelerated filer [X] (Do not                      
Large accelerated filer [ ]Accelerated filer [ ]
Non-accelerated filer [X]Smaller reporting company [ ]
check if a smaller reporting company)
Indicate by check mark whether the registrantRegistrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ]    No [X]

As of June 30, 20122015 (and currently), all of the common stock of Wisconsin Electric Power Company is held by WisconsinWEC Energy Corporation.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (January 31, 2013):

Group, Inc.

Common Stock, $10 Par Value, 33,289,327State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant.
None.

Number of shares outstanding of each class of common stock, as of
January 31, 2016


Common Stock, $10 par value, 33,289,327 shares outstanding



Documents Incorporatedincorporated by Referencereference:

Portions of Wisconsin Electric Power Company's Definitive information statement on Schedule 14C for its Annual Meeting of Stockholders, to be held on April 25, 2013,28, 2016, are incorporated by reference into Part III hereof.


2012 Form 10-K


WISCONSIN ELECTRIC POWER COMPANY
FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2012



Table of Contents

WISCONSIN ELECTRIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2015
TABLE OF CONTENTS
TABLE OF CONTENTS
ItemPage
  
PART I
  Page
1.       Business
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
101
PART I
3
ITEM 1.
BUSINESS
3
 
1A.    Risk Factors
A.
23INTRODUCTION
3
 
1B.    Unresolved Staff Comments
B.
31UTILITY OPERATIONS
3
 
2.       Properties
C.
31REGULATION
12
 
3.       Legal Proceedings
D.
33ENVIRONMENTAL COMPLIANCE
14
 
E.
EMPLOYEES
15
4.       Mine Safety Disclosures
ITEM 1A.
34RISK FACTORS
16
ITEM 1B.
UNRESOLVED STAFF COMMENTS
24
ITEM 2.
PROPERTIES
25
ITEM 3.
LEGAL PROCEEDINGS
26
ITEM 4.
MINE SAFETY DISCLOSURES
26
 
EXECUTIVE OFFICERS OF THE REGISTRANT
27
Executive Officers of the Registrant
PART II
3529
ITEM 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
29

ITEM 6.
SELECTED FINANCIAL DATA
30
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
31
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
48
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
49
 
PART II
5.       Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
          Equity SecuritiesA.
37Report of Independent Registered Public Accounting Firm
49
 
B.
Consolidated Income Statements
50
6.       Selected Financial Data
38C.
Consolidated Balance Sheets
51
D.
Consolidated Statements of Cash Flows
52
E.
Consolidated Statements of Equity
53
F.
Consolidated Statements of Capitalization
54
G.
Notes to Consolidated Financial Statements
55
  
7.       Management's Discussion and Analysis of Financial Condition and Results of Operations
Note 1
39Summary of Significant Accounting Policies
55
  
7A.    Quantitative and Qualitative Disclosures About Market Risk
Note 2
65Acquisition
60
  
8.       Financial Statements and Supplementary Data
Note 3
66Related Parties
61
 Consolidated Income Statements
66Note 4
Investment in American Transmission Company
62
 Consolidated Balance Sheets --
Note 5
Supplemental Cash Flow Information
63
Note 6
Regulatory Assets and Liabilities
63
Note 7
Property, Plant, and Equipment
64
Note 8
Asset Retirement Obligations
65
Note 9
Common Equity
65
Note 10
Preferred Stock
67
 Consolidated Balance Sheets -- Capitalization and Liabilities
68
 Consolidated Statements of Cash Flows
69Note 11
Short-Term Debt and Lines of Credit
67
 Consolidated Statements of Capitalization
70Note 12
Consolidated Statements of Common Equity
71
Notes to Consolidated Financial Statements
72
Note ASummary of Significant Accounting Policies
72
Note BRecent Accounting Pronouncements
75
Note CRegulatory Assets and Liabilities
75
Note DDivestitures
76
Note EAsset Retirement Obligations
76
Note FVariable Interest Entities
76
Note GIncome Taxes
76
Note HCommon Equity
79
Note ILong-Term Debt and Capital Lease Obligations
8368
 Note JShort-Term Debt
85Note 13
Income Taxes
70
 Note KDerivative Instruments
86Note 14
Employee Benefits
72
Note 15
Commitments and Contingencies
76

2015 Form 10-K3iWisconsin Electric Power Company
Table of Contents
2012 Form 10-K

TABLE OF CONTENTS - (Cont'd)

Item  Page
Note 16
Fair Value Measurements
83
 
Note L17
Fair Value Measurements
Derivative Instruments
84
Note 18
Variable Interest Entities
84
Note 19
Regulatory Environment
85
Note 20
Michigan Settlement
86
Note 21
Segment Information
87
 
Note M22
Benefits
Quarterly Financial Information (Unaudited)
88
Note 23
New Accounting Pronouncements
88
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
89
ITEM 9A.
Note N
CONTROLS AND PROCEDURES
Segment Reporting
89
ITEM 9B.
OTHER INFORMATION
89
PART III
90
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT
90
ITEM 11.
EXECUTIVE COMPENSATION
90
ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
90

ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
90
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
91
PART IV
92
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
92
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
93
SIGNATURES
94
Note ORelated Parties
EXHIBIT INDEX
95
Note PCommitments and Contingencies
97
Note QSupplemental Cash Flow Information
99
Report of Independent Registered Public Accounting Firm
100
9.       Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
101
9A.   Controls and Procedures
101
9B.    Other Information
101
PART III
10.    Directors, Executive Officers and Corporate Governance of the Registrant
102
11.    Executive Compensation
102
12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
         Matters
102
13.    Certain Relationships and Related Transactions, and Director Independence
103
14.    Principal Accountant Fees and Services
103
PART IV
15.    Exhibits and Financial Statement Schedules
103
Schedule II - Valuation and Qualifying Accounts
105
Signatures
106
Exhibit Index
E-1


2015 Form 10-K4iiWisconsin Electric Power Company
Table of Contents
2012 Form 10-K

GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
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 SubsidiarySubsidiaries and Affiliates  
ATCAmerican Transmission Company LLC
Bostco Bostco LLC
DATCDuke-American Transmission Company
IntegrysIntegrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
WBSWEC Business Services LLC
We Power W.E. Power, LLC
WisconsinWEC Energy Group WEC Energy Group, Inc. (previously known as Wisconsin Energy CorporationCorporation)
Wisconsin Gas Wisconsin Gas LLC
   
SignificantCertain Assets  
OC 1 Oak Creek expansionExpansion Unit 1
OC 2 Oak Creek expansionExpansion Unit 2
PIPP Presque Isle Power Plant
PSGS Paris Generating Station
PWGS Port Washington Generating Station
PWGS 1 Port Washington Generating Station Unit 1
PWGS 2 Port Washington Generating Station Unit 2
VAPP Valley Power Plant
   
Other Affiliates
ATCAmerican Transmission Company LLC
Federal and State Regulatory Agencies
CFTCCommodity Futures Trading Commission
DOEUnited States Department of Energy
DOJWisconsin Department of Justice
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
IRSMDEQ Internal Revenue ServiceMichigan 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
   
Accounting Terms
AFUDCAllowance for Funds Used During Construction
AROAsset Retirement Obligation
ASCAccounting Standards Codification
ASUAccounting Standards Update
FASBFinancial Accounting Standards Board
GAAPGenerally Accepted Accounting Principles
OPEBOther Postretirement Employee Benefits

2015 Form 10-KiiiWisconsin Electric Power Company
Table of Contents

Environmental Terms
Act 141 2005 Wisconsin Act 141
BARTBest Available Retrofit Technology
BTABest Technology Available
CAA Clean Air Act
CAIRClean Air Interstate Rule
CO2
 Carbon Dioxide
CSAPR Cross-State Air Pollution Rule
GHGGreenhouse Gas
MATS Mercury and Air Toxics Standards

5Wisconsin Electric Power Company
2012 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:
NAAQS National Ambient Air Quality Standards
NOVNotice of Violation
NOx
NOx		 Nitrogen Oxide
PM2.5
Fine Particulate Matter
RACTReasonably Available Control Technology
SIPState Implementation Plan
SO2
 Sulfur Dioxide
Other Terms and Abbreviations
AQCSAir Quality Control System
ARRsAuction Revenue Rights
BechtelBechtel Power Corporation
Compensation CommitteeCompensation Committee of the Board of Directors of Wisconsin Energy
CPCNCertificate of Public Convenience and Necessity
Dodd-Frank ActDodd-Frank Wall Street Reform and Consumer Protection Act
ERISAEmployee Retirement Income Security Act of 1974
Exchange ActSecurities Exchange Act of 1934, as amended
FitchFitch Ratings
FTRsFinancial Transmission Rights
GCRMGas Cost Recovery Mechanism
LMPLocational Marginal Price
MISOMidwest Independent Transmission System Operator, Inc.
MISO Energy MarketsMISO Energy and Operating Reserves Market
MontfortMontfort Wind Energy Center
Moody'sMoody's Investor Service
NDAANational Defense Authorization Act
NYMEXNew York Mercantile Exchange
OTCOver-the-Counter
PlanThe Wisconsin Energy Corporation Retirement Account Plan
Point BeachPoint Beach Nuclear Power Plant
PTFPower the Future
RTORegional Transmission Organization
Settlement AgreementSettlement Agreement and Release between Elm Road Services, LLC    and Bechtel effective as of December 16, 2009
S&PStandard & Poor's Ratings Services
WPLWPDES Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp.
WolverineWolverine Power Supply Cooperative, Inc.Pollutant Discharge Elimination System
   
Measurements  
Btu British Thermal Unit(s)
Dth Dekatherm(s) (One Dth equals one million Btu)
kW Kilowatt(s) (One kW equals one thousand Watts)

6Wisconsin Electric Power Company
2012 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:
kWh Kilowatt-hour(s)
MW Megawatt(s) (One MW equals one million Watts)
MWh Megawatt-hour(s)
WattA measure of power production or usage
   
AccountingOther Terms and Abbreviations
ARRs Auction Revenue Rights
AFUDCCompensation Committee Allowance for Funds Used During ConstructionCompensation Committee of the Board of Directors of WEC Energy Group
AROCPCN Asset Retirement ObligationCertificate of Public Convenience and Necessity
ASUExchange Act Accounting Standards UpdateSecurities Exchange Act of 1934, as amended
CWIPConstruction Work in Progress
FASBFTRs Financial Accounting Standards BoardTransmission Rights
GAAPGCRM Generally Accepted Accounting PrinciplesGas Cost Recovery Mechanism
IFRSLMP International Financial Reporting StandardsLocational Marginal Price
OPEBMerger Agreement Other Post-Retirement Employee BenefitsAgreement and Plan of Merger, dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation
MISO Midcontinent Independent System Operator, Inc.
MISO Energy MarketsMISO Energy and Operating Reserves Market
N/ANot Applicable
NYMEXNew York Mercantile Exchange
Point BeachPoint Beach Nuclear Power Plant
PTFPower the Future
ROEReturn on Equity
RTORegional Transmission Organization
SSRSystem Support Resource
Treasury GrantSection 1603 Renewable Energy Treasury Grant


2015 Form 10-K7ivWisconsin Electric Power Company
Table of Contents
2012 Form 10-K

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

CertainIn this report, we make statements contained in this reportconcerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, 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.amended. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of construction projects, regulatory matters, on-going legal proceedings, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking terminologyterms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets" or similar terms"targets," "will," or variations of these terms.

Actual results may differ materially from those set forth in forward-looking statements. In addition to the assumptionsForward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other factors referredregulations and associated compliance costs, legal proceedings, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, liquidity and capital resources, and other matters.

Forward-looking statements are subject to specifically in connection with these statements, factorsa number of risks and uncertainties that could cause our actual results to differ materially from those contemplatedexpressed or implied in any forward-looking statements or otherwise affect our future results of operationsthe statements. These risks and financial conditionuncertainties include among others, the following:those described in Item 1A. Risk Factors and those identified below:

Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or terrorism-related damage; cyber-security threatsnatural gas pipeline system constraints;

Factors affecting the demand for electricity 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; unanticipatednatural gas, including political developments, unusual weather, changes in fossil fuel, purchased power, coal supply, gas supply or water supplyeconomic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;

The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs or availabilityand the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated businesses;

The ability to obtain and retain customers, including wholesale customers, due to higher demand, shortages, transportation problemsincreased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;

The timely completion of capital projects within budgets, as well as the recovery of the related costs through rates;

The impact of federal, state, and local legislative and regulatory changes, including changes in rate-setting policies or procedures, tax law changes, including the extension of bonus depreciation, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, and energy efficiency mandates;

Federal and state legislative and regulatory changes relating to the environment, including climate change and other developments; unanticipatedenvironmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the cost orinterpretation of permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate new environmental controls at our electric generating facilities, or replace and/or repair our electric and gas distribution systems;water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts; environmental incidents; electric transmissioncontracts, or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; or inflation rates.other developments;

Factors affectingChanges in credit ratings, interest rates, and our ability to access the demand for electricitycapital markets, caused by volatility in the global credit markets, our capitalization structure, and natural gas, including weather and other natural phenomena;market perceptions of the economic climate in our service territories; customer growth and declines; customer business conditions, including demand for their products and services; and energy conservation efforts.utility industry or us;

Timing, resolutionCosts and impacteffects of future rate caseslitigation, administrative proceedings, investigations, settlements, claims, and negotiations, including recovery of costs associated with environmental compliance, renewable generation, transmission service, distribution system upgrades, fuel and the Midwest Independent Transmission System Operator, Inc. (MISO) Energy Markets.

Increased competition in our electric and gas markets and continued industry consolidation.inquiries;

The abilityrisk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to control costs and avoid construction delays during the development and construction of new environmental controls and renewable generation, as well as upgrades to our electric and natural gas distribution systems.meet their obligations;

The impact of recent and future federal, state and local legislative and regulatory changes, including any changes in rate-setting policies or procedures; electric and gas industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; any required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities or cybersecurity threats; required approvals for new construction, and the siting approval process for new generation and transmission facilities and new pipeline construction; changes to the Federal Power Act and related regulations and enforcement thereof by the Federal Energy Regulatory Commission (FERC) and other regulatory agencies; changes in allocation of energy assistance, including state public benefits funds; changes in environmental, tax and other laws and regulations to which we are subject; changes in the application of existing laws and regulations; and changes in the interpretation or enforcement of permit conditions by the permitting agencies.

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

2015 Form 10-K81Wisconsin Electric Power Company
Table of Contents
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION - (Cont'd)2012 Form 10-K


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

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

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

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

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

The impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) and any regulations promulgated thereunder, including rules recently adopted and/or proposed by the Commodity Futures Trading Commission (CFTC) that may impact our hedging activities and related costs.

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

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

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

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

The abilitydirect or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber intrusion, including the failure to obtainmaintain the security of personally identifiable information, the associated costs to protect our assets and retain short-personal information, and long-term contracts with wholesale customers.the costs to notify affected persons to mitigate their information security concerns;

Potential strategic business opportunities, including acquisitions and/or dispositionsThe financial performance of assets or businesses, which we cannot ensure will be beneficialATC and its corresponding contribution to our earnings, as well as the ability of ATC and DATC to obtain the required approvals for us.their transmission projects;

IncidentsThe investment performance of WEC Energy Group's employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

Factors affecting the U.S. electric grid or operationemployee workforce, including loss of generating facilities.key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

ForeignAdvances in technology that result in competitive disadvantages and create the potential for impairment of existing assets;

The terms and conditions of the governmental economic, political and currency risks.regulatory approvals of WEC Energy Group's acquisition of Integrys that could reduce anticipated benefits and the ability to successfully integrate the operations of the combined company;

The timing and outcome of any audits, disputes, and other proceedings related to taxes;

The effect of accounting pronouncements issued periodically by standard-setting bodies; and

Other business or investment considerations that may be disclosed from time to timeelsewhere herein and in our Securities and Exchange Commission (SEC) filingsother reports we file with the SEC or in other publicly disseminated written documents, including the risk factors set forth in Item 1A of this report.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.


2015 Form 10-K92Wisconsin Electric Power Company
Table of Contents

PART I


ITEM 1.BUSINESS
ITEM 1. BUSINESS

A. INTRODUCTION

In this report, when we refer to "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and our subsidiary, Bostco. References to "Notes" are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

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

We conduct our operations primarily in three reportable segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,125,700 electric customers in Wisconsin and theMichigan's Upper Peninsula of Michigan, approximately 468,600 gas customers in Wisconsin and approximately 460 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our businessPeninsula. Our three reportable segments see Results of Operations in Item 7 and Note N -- Segment Reporting in the Notes to Consolidated Financial Statements in Item 8.

Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas), aare electric utility, natural gas distributionutility, and steam utility, which serves customers throughout Wisconsin;accounted for 89%, 10%, and W.E. Power, LLC (We Power), a non-utility company that was formed1% of total utility revenues, respectively, in 2001 to design, construct, own and lease to us the new generating capacity included in Wisconsin Energy's Power the Future (PTF) strategy. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies."

2015. Bostco is our non-utility subsidiary that develops and invests in real estate. As

For more information about our utility operations, including financial and geographic information, see Note 21, Segment Information, and Item 7, Management's Discussion and Analysis of December 31, 2012, Bostco had $30.2 millionFinancial Condition and Results of assets.Operations – Results of Operations.

Acquisition

On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys, and changed its name to WEC Energy Group, Inc. For additional information on this acquisition, see Note 2, Acquisition.

Available Information

Our annual and periodicalperiodic filings with the SEC are available, free of charge, through Wisconsin Energy's InternetWEC Energy Group's website www.wisconsinenergy.com. These documents are availablewww.wecenergygroup.com, as soon as reasonably practicable after such materialsthey are filed (or furnished) with or furnished to the SEC.

You may obtain materials we filed with or furnished to the SEC at the SEC Public Reference Room at 100 F Street, NE, Washington, DC 20549. To obtain information on the operation of the Public Reference Room, you may call the SEC at 1-800-SEC-0330. You may also view information filed or furnished electronically with the SEC at the SEC's website at www.sec.gov.

B. UTILITY OPERATIONS

ELECTRIC UTILITY OPERATIONSSEGMENT

We are the largest electric utility in the state of Wisconsin. We generate and distribute electric energy to customers located in a territory that includes southeastern Wisconsin (including the metropolitan Milwaukee area), east central andWisconsin, northern Wisconsin, and theMichigan's Upper PeninsulaPeninsula.


2015 Form 10-K3Wisconsin Electric Power Company
Table of Michigan.Contents

Electric Utility Operating Statistics

We participate inThe following table shows certain electric utility operating statistics for 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.past three years:
  Year Ended December 31
  2015 2014 2013
Operating revenues (in millions)
      
Residential $1,207.6
 $1,199.3
 $1,208.6
Small commercial and industrial 1,035.4
 1,052.9
 1,048.0
Large commercial and industrial 726.7
 637.0
 711.9
Other 22.1
 23.0
 23.4
Total retail revenues 2,991.8
 2,912.2
 2,991.9
Wholesale 101.4
 131.9
 143.7
Resale 228.2
 264.1
 143.2
Other operating revenues 89.6
 87.8
 28.4
Total 3,411.0
 3,396.0
 3,307.2
Electric customer choice * 2.4
 5.1
 1.5
Total operating revenues $3,413.4
 $3,401.1
 $3,308.7
       
Customers – end of year (in thousands)
      
Residential 1,020.8
 1,015.0
 1,010.5
Small commercial and industrial 116.0
 115.4
 114.6
Large commercial and industrial 0.7
 0.7
 0.7
Other 2.6
 2.5
 2.6
Total customers 1,140.1
 1,133.6
 1,128.4
       
Customers – average (in thousands)
 1,136.5
 1,130.7
 1,126.9

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

Electric Sales

Our electric energy deliveries included supply and distribution sales to all classesretail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier. In 2015, retail electric revenues accounted for 87.6% of customers totaled approximately 30.3 milliontotal electric operating revenues, while wholesale (including resale) electric revenues accounted for 9.7% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Electric Utility Segment Contribution to Operating Income for information on MWh during 2012 and approximately 31.3 million MWh during 2011. We had approximately 1,125,700 electric customers as of December 31, 2012 and 1,122,500 electric customers as of December 31, 2011.sales by customer class.

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

We alsobuy and sell wholesale electric power withinby participating in the MISO Energy Markets. The cost of our generation offered into the MISO Energy Markets, compared to our competitors, affects how often our generating units are dispatched and how we buy and sell power. For more information, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations –Factors Affecting Results, Liquidity, and Capital Resources – Industry Restructuring.

Electric Sales Growth:   Our service territory experienced flat sales in 2012 as positive customer growth was offset by reduced use per customer. Our weather normalized 2012 retail electric sales, excluding our two largest

10Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 Form 10-K

customers (two iron ore mines) and two large industrial customers that switched to self-generation, were almost equal to our normalized 2011 electric sales. 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 0.5% to 1.0% over the next five years (excluding sales to the two iron ore mines). These estimates assume normal weather.

Sales to Large Electric Retail Customers:Customers

We provide electric utility service to a diversified base of customers in such industries as mining, paper, foundry, food products and machinery production, as well as tohealth services, governmental, and large retail chains.

Our In February 2015, our largest retail electric customers arecustomer, the owner of two iron ore mines located in theMichigan's Upper Peninsula, of Michigan. The combinedreturned as a customer after choosing an alternative electric energy sales to the two mines accounted for 6.6% and 7.1% of our total electric utility energy sales during 2012 and 2011, respectively. The mines have notified us that they expect production at onesupplier in September 2013. We entered into a special contract with each of the mines to be reduced in 2013.

Salesprovide full requirements electric service through December 31, 2019. In 2015, we deferred, and we expect to Wholesale Customers:   During 2012, we sold wholesale electric energycontinue to one municipally owned system, two rural cooperativesdefer, the margin from those sales and two municipal joint action agencies located inwill apply these amounts for the statesbenefit of Wisconsin and Michigan. Our wholesaleretail electric energy sales were also made to 16 other public utilities and power marketers throughout the region under rates approved by FERC. Wholesale sales accounted for approximately 10.6% of our total electric energy sales and 6.2% of total electric operating revenues during 2012, compared with 13.1% of total electric energy sales and 7.0% of total electric operating revenues during 2011.

Electric System Reliability Matters:   Our electric sales are impacted by seasonal factors and varying weather conditions. We sellcustomers in a future rate proceeding. For 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 all of our firm electric load obligations during 2012 and expect to have adequate capacity to meet all of our firm obligations during 2013. For additional information, see Note 20, Michigan Settlement, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in Item 7.– Industry Restructuring.

2015 Form 10-K4Wisconsin Electric Power Company
Table of Contents


Wholesale Customers

CompetitionWe provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers. Wholesale sales accounted for 3.4%, 5.3%, and 5.9% of total electric energy sales during 2015, 2014, and 2013, respectively. Wholesale revenues accounted for 3.0%, 3.9%, and 4.3% of total electric operating revenues during 2015, 2014, and 2013, respectively.

Resale

The regulatedmajority of our sales for resale are sold to one RTO, MISO, at market rates based on availability of our generation and RTO demand. Resale sales accounted for 23.8%, 18.5%, and 13.3% of total electric energy industry continues to experience significant structural changes. Increased competition in the retailsales during 2015, 2014, and wholesale markets may result from restructuring efforts. It is uncertain when, if ever, retail access might be implemented in Wisconsin. Michigan has adopted retail choice which allows customers to remain with their regulated utility at regulated rates or choose an alternative2013, respectively. Resale revenues accounted for 6.7%, 7.8%, and 4.3% of total electric supplier to provide power supply service. We continue providing distributionoperating revenues during 2015, 2014, and customer service functions regardless of the customer's power supplier. Although competition and customer switching to alternative suppliers in our service territories in Michigan has been limited, the additional competitive pressures resulting from retail access could lead to a loss of customers.2013, respectively.

Electric Sales Growth

Our service territory experienced slightly declining weather-normalized retail electric sales in 2015 as positive customer growth was more than offset by reduced volumes related to lower use per customer. We currently forecast retail electric sales volumes, excluding the two iron ore mines, to grow at a compound annual rate of between flat and 0.5% over the next five years, assuming normal weather. In addition, we forecast associated electric peak demand, excluding the two iron ore mines, to grow at a compound annual rate of between 0.5% to 1.0% over the next five years, also assuming normal weather. The owner of the two iron ore mines has announced its intention to shut down one of the mines in 2017. The potential loss of retail electric sales associated with this mine is estimated at approximately 3% of our annual total retail electric sales.

Electric Generation and Supply Mix

Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to maintain a stable, reliable, and affordable supply of electricity. We supply a significant amount of electricity to our customers from power plants that we own or lease.lease from We Power. 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,Power Purchase Commitments, below and through spot purchases in the MISO Energy Markets.


11Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 Form 10-K

Our dependable capabilityrated capacity by fuel type, including the units we lease from We Power, as of December 31 is shown below:

below. For more information on our electric generation facilities, see Item 2. Properties.
  Dependable Capability in MW (a)
  2012 2011 2010
Coal (b) 3,828
 3,904
 3,671
Natural Gas - Combined Cycle 1,090
 1,090
 1,090
Natural Gas/Oil - Peaking Units (c) 962
 967
 1,005
Renewables (d) 107
 80
 83
Total 5,987
 6,041
 5,849
  
Rated Capacity in MW (1)
  2015 2014 2013
Coal 3,589
 3,707
 3,822
Natural gas:      
Combined cycle 1,082
 1,082
 1,082
Steam turbine (2)
 240
 118
 —
Natural gas/oil peaking units (3)
 962
 962
 962
Renewables (4)
 187
 155
 155
Total rated capacity by fuel type 6,060
 6,024
 6,021

(a)
(1)
Dependable capabilityRated capacity 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.utility, and amounts are based on expected capacity ratings for the following summer. The values were established by tests and may change slightly from year to year.

(b)
(2)
The increasenatural gas steam turbine represents the rated capacity associated with the VAPP Units, which were converted from coal to natural gas in 2011 as compared to 2010 reflects the January 2011 in-service date of Oak Creek expansion Unit 2 (OC 2), partially offset by the March 2011 sale of our interest in Edgewater Generating Unit 5. Our share of the dependable capability of OC 2 is 528 MW.
2014 and 2015.

(c)
(3)
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 natural gas distribution company that delivers natural gas to the plants.

(d)
(4)
Includes hydroelectric, biomass, and wind generation.


2015 Form 10-K5Wisconsin Electric Power Company
Table of Contents

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2012, as well as estimates for 2016:
  Estimate Actual
  2016 2015 2014 2013
Company-owned or leased generation units:        
Coal 52.2% 53.5% 55.2% 53.6%
Natural gas:        
Combined cycle 15.5% 13.0% 8.7% 10.1%
Steam turbine 1.1% 1.4% 0.2% —%
Natural gas/oil peaking units 0.1% 0.6% 0.2% 0.2%
Renewables 3.1% 3.5% 3.8% 3.3%
Total company-owned or leased generation units 72.0% 72.0% 68.1% 67.2%
Power purchase contracts:        
Nuclear 22.7% 24.5% 25.4% 27.1%
Natural gas 3.3% 1.7% 2.1% 2.1%
Renewables 1.2% 1.1% 2.7% 3.1%
Other 0.7% 0.7% 0.9% 0.5%
Total power purchase contracts 27.9% 28.0% 31.1% 32.8%
Purchased power from MISO 0.1% —% 0.8% —%
Total purchased power 28.0% 28.0% 31.9% 32.8%
Total electric utility supply 100.0% 100.0% 100.0% 100.0%

Coal-Fired Generation

Our coal-fired generation, including the units we lease from We Power, consists of five operating plants with a rated capacity of 3,589 MW as of December 31, 2015. For more information about our operating plants, see Item 2. Properties.

Natural Gas-Fired Generation

Our natural gas-fired generation, including the units we lease from We Power, consists of four operating plants, including peaking units, with a rated capacity of 2,104 MW as of December 31, 2015. For more information about our operating plants, see Item 2. Properties.

Oil-Fired Generation

Fuel oil is used for combustion turbines at certain of our natural gas-fired plants as well as for ignition and flame stabilization at one of our coal-fired plants. Our oil-fired generation had a rated capacity of 180 MW as of December 31, 2015. We also have natural gas-fired peaking units with a rated capacity of 782 MW, which have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our operating plants, see Item 2. Properties.

Renewable Generation

Hydroelectric

Our hydroelectric generating system consists of 13 operating plants with a total installed capacity of 86 MW and a rated capacity of 86 MW as of December 31, 2015. All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Wind

We have four wind sites, consisting of 200 turbines, with an estimateinstalled capacity of 339 MW and a rated capacity of 51 MW as of December 31, 2015.


2015 Form 10-K6Wisconsin Electric Power Company
Table of Contents

Biomass

We constructed a biomass-fueled power plant at a Rothschild, Wisconsin paper mill site that went into commercial operation in November 2013. Wood waste and wood shavings are used to produce a rated capacity of approximately 50 MW of electric power as well as steam to support the paper mill's operations. Fuel for the power plant is supplied by both the paper mill and through contracts with biomass suppliers.

Generation from Leased Power The Future Units

We also supply electricity to our customers from power plants that we lease from We Power. These plants include the Oak Creek Expansion units and the PWGS units, otherwise known as the PTF units. Lease payments are billed from We Power to us and then recovered in our rates as authorized by the PSCW, the MPSC, and the FERC. We operate the PTF units and are authorized by the PSCW and state law to fully recover prudently incurred operating and maintenance costs in our Wisconsin electric rates. As the operator of the units, we may request We Power to make capital improvements to, or further investments in, the units. Under the lease terms, these capital improvements or further investments will increase lease payments paid by us and should ultimately be recovered in our rates.

Electric System Reliability

The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. The PSCW has a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO has a 14.3% reserve margin requirement from January 1, 2016, through May 31, 2016, and 15.2% for the remainder of 2016. The MPSC does not have minimum guidelines for future supply reserves.

We had adequate capacity through company-owned generation units, leased generating units, and power purchase contracts to meet the MISO calculated planning reserve margin during 2015 and expect to have adequate capacity to meet the planning reserve margin requirements during 2016.2013: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. Load management procedures allow for the reduction of energy use through agreements with customers to directly shut off their equipment or through interruptible service, where customers agree to reduce their load in the case of an emergency interruption.

Fuel and Purchased Power Costs
  Estimate Actual
  2013 2012 2011 2010
Coal 56.0% 43.0% 54.2% 53.9%
Natural Gas - Combined Cycle 7.5% 15.9% 6.6% 8.4%
Wind 2.3% 2.3% 1.0% 1.0%
Hydroelectric 1.1% 0.7% 1.0% 1.0%
Natural Gas/Oil - Peaking Units 0.1% 0.7% 0.1% 0.3%
Biomass 0.1% —% —% —%
Net Generation 67.1% 62.6% 62.9% 64.6%
Purchased Power 32.9% 37.4% 37.1% 35.4%
Total 100.0% 100.0% 100.0% 100.0%

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 set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. For more information about the fuel rule, see Item 1. Business – C. Regulation.

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

31:
  2012 2011 2010
Coal $30.71
 $29.78
 $26.44
Natural Gas - Combined Cycle $23.62
 $38.02
 $43.14
Natural Gas/Oil - Peaking Units $53.40
 $119.83
 $97.36
Purchased Power $41.92
 $42.79
 $43.11
  2015 2014 2013
Coal $25.25
 $27.68
 $27.97
Natural gas combined cycle 23.44
 40.64
 32.22
Natural gas/oil peaking units 56.33
 129.83
 83.95
Purchased power 43.87
 47.47
 43.74

Historically,We purchase coal has been purchased under long-term contracts, which helpedhelps with price stability. Coal and associated transportation services have continued to see volatility in pricing due to increasedchanging 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.


12Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 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 2013, 90% of our projected coal requirements of 10.7 million tons are under contracts which are not tied to 2013 market pricing fluctuations. At the end of 2012, our coal-fired generation consisted of six operating plants with a dependable capability of approximately 3,828 MW.

The annual tonnage amounts contracted for 2013 through 2015 are as follows:

Year Annual Tonnage
  (Thousands)
   
2013 9,586
2014 5,753
2015 4,000

Coal Deliveries:   All of our 2013 coal requirements are expected to be delivered by unit trains owned or leased by us. The unit trains will transport coal for the Oak Creek and Pleasant Prairie Power Plants from Wyoming mines, and transport coal for the Oak Creek expansion units from Pennsylvania and Wyoming. 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 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,traded. Therefore, we use financial heating oil contracts to mitigate risk related to diesel fuel prices.


2015 Form 10-K7Wisconsin Electric Power Company
Table of Contents

We purchase natural gas for our plants on the spot market from natural 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 our plants' variable usage.

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.

Edgewater Generating Unit 5:   On March 1, 2011, we sold our 25% interest in Edgewater Generating Unit 5 to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp. (WPL), for our net book value, including working capital, of approximately $38 million.

Wolverine Joint Ownership Agreement:In November 2012, we entered into a joint ownership agreement with Wolverine Power Supply Cooperative, Inc. (Wolverine) regarding the Presque Isle Power Plant (PIPP), whereby Wolverine will pay for the installation of environmental controls at the plant and will receive a minority ownership interest in the plant in return. We will continue to operate the plant. The transaction and the environmental controls to be installed will require approvals from various state and federal agencies, including the PSCW, the MPSC, the Michigan Department of Environmental Quality and the FERC.

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 1,872 MW as of December 31, 2012.

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, balancing and storage agreements intended to support the plants' variable usage.


13Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 Form 10-K

Wealso have a PSCW-approved hedging program that allows us to hedge up to 65% of our estimated natural gas usageuse for electric generation in order to help manage our natural gas price risk. This hedging program is generally implemented on a 36-month forward-looking basis. The results of both of these programs are reflected in the average costs of this program are included in our fuelnatural gas and purchased power costs.power.

Oil-Fired GenerationCoal Supply

Fuel oil is usedWe diversify the coal supply for the combustion turbines at the Germantown Power Plant units 1-4, boiler ignition and flame stabilization at the Presque Isle Power Plant, and diesel engines at the Pleasant Prairie Power Plant and Valley Power Plant (VAPP). Our oil-fired generation had a dependable capabilityour electric generating facilities by purchasing coal from several mines in Wyoming, as well as from various other states. For 2016, approximately 86% of our total projected coal requirements of approximately 180 MW12 million tons are contracted under fixed-price contracts. See Note 15, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

The annual tonnage amounts contracted for 2016 through 2018 are as follows:
(in thousands) Annual Tonnage
2016 9,978
2017 6,967
2018 3,583

Coal Deliveries

All of December 31, 2012. Our natural gas-fired peaking units have the ability to burn oil if natural gas is not available due to delivery constraints. Fuel oilour 2016 coal requirements are purchasedexpected to be shipped by our owned or leased unit trains under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming, Pennsylvania, and Montana. The coal is transported by train to our rail-served electric-generating facilities and to dock storage in Superior, Wisconsin, until needed by our lake vessel-served facilities. Additional small volume agreements with suppliers.

Renewable Generation

Hydroelectric:   Our hydroelectric generating system consists of 13 operating plants with a total installed capacity of approximately 88 MW and a dependable capability of approximately 40 MW as of December 31, 2012. 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 purchased Montfort Wind Energy Center (Montfort) from NextEra Energy Resources on December 21, 2012 for $27 million. We now have four wind sites, consisting of 200 turbines with an installed capacity of 338 MW and a dependable capability of 67 MW.

Biomass:   We are constructing a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site. Wood waste and wood shavings willmay also be used to produce approximately 50 MW of renewable electricitysupplement the normal coal supply for our facilities.

Midcontinent Independent System Operator Costs

In connection with its status as a FERC approved RTO, MISO developed and will also support Domtar's sustainable papermaking operations. Construction commenced in June 2011.operates the MISO Energy Markets, which include its bid-based energy markets and ancillary services market. We currently expect to invest between $245 million and $255 million, excluding Allowance for Funds Used During Construction (AFUDC),are a participant in the plant. We are targeting completionMISO Energy Markets. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas, and Missouri, a region referred to as MISO South. These changes have not had a material impact on our allocation of transmission costs, and we do not expect them to have a material impact in the facility by the end of 2013.future. For more information on MISO, see Item 1. Business – C. Regulation.

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 identifiesAs of December 31, 2015, our power purchase commitments as of December 31, 2012 with unaffiliated parties for the next five years:

Year MW (a)
   
2013 1,267
2014 1,267
2015 1,267
2016 1,267
2017 1,267

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

The above commitments include approximately 1,030years is 1,267 MW per year. This amount includes 1,033 MW per year related to the Point Beacha long-term power purchase agreement. Under this agreement we pay a predetermined pricefor electricity generated by Point Beach. In addition, 234 MW per MWh for energy delivered accordingyear relates to a schedule included inlong-term power purchase agreement under which we purchase power at a price determined monthly based on a formula tied to a natural gas price index.

Other Matters

Seasonality

Our electric sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the agreement. The balancesummer months because of thesethe residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. 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, we did not require public appeals for conservation, and we did not interrupt or curtail service to non-firm customers who participate in load management programs.

2015 Form 10-K8Wisconsin Electric Power Company
Table of Contents


Competition

We face competition from various entities and other forms of energy sources available to customers, including self-generation by large industrial customers and alternative energy sources. We compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.

The retail electric utility market in Wisconsin is a tolling arrangement whereby we are responsible forregulated by the procurement, deliveryPSCW. Retail electric customers do not have the ability to choose their electric supplier, and it is uncertain when, if ever, retail electric choice might be implemented in Wisconsin. The regulated energy industry continues to experience significant structural changes, which could eventually lead to increased competition in Wisconsin.

The retail electric utility market in Michigan remains open to competition with its retail choice program, 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 costcustomer's power supplier.

Environmental Matters

For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 15, Commitments and Contingencies, and Item 7. Management's Discussion and Analysis of natural gas fuel related to a specific unit identified in the contract.Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Environmental Matters.

Electric Transmission and Energy Markets

American Transmission Company:Company 

ATC is a regional transmission company that owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Illinois.Minnesota. ATC is expected to provide comparable service to all customers, including us, and to support effective competition in energy markets without

14Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 Form 10-K

favoring any market participant. ATC is regulated by the FERC for all rate terms and conditions of service and is a transmission-owning member of MISO. MISO maintains operational control of ATC's transmission system, and we are a non-transmission owning member and customer of MISO. We owned approximately 23.0%As of ATC as of December 31, 2012 and 20112015, our ownership interest in ATC was approximately 23%. For additionalSee Note 4, Investment in American Transmission Company, for more information see Note O -- 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,DATC, that will seek opportunities to acquire, build, own, and operate new electric transmission infrastructure in North America to address increasing demand for affordable, reliable transmission capacity. In April 2013, DATC acquired a 72% interest in California's Path 15 transmission line. DATC continues to evaluate new projects and opportunities, along with participating in the competitive bidding process on projects it considers viable. These projects are located in the service territories of several different RTOs around the country. On January 20, 2016, the FERC issued an order authorizing ATC to enter into a proposed restructuring involving the creation of three new entities: ATC Holdco, ATC Development, and ATC Development Manager Inc. ATC’s current member owners will have the option to retain their existing ownership interests limited to ATC in Wisconsin and adjacent states or to exchange their current ATC ownership interests for ownership interests in ATC Holdco, which would allow them to participate in ATC's transmission business in Wisconsin and adjacent states, as well as new transmission development projects throughout the U.S.

MISO:   In connectionATC is currently named in a complaint filed with its status asthe FERC requesting a FERC approved Regional Transmission Organization (RTO),reduction in the base ROE used by MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energytransmission owners. See Item 7. Management's Discussion and Operating Reserves Markets, which includes the bid-based energy marketsAnalysis of Financial Condition and the ancillary services market. For further information on MISO and the MISO Energy Markets, seeResults of Operations – Factors Affecting Results, Liquidity, and Capital Resources -- Industry Restructuring and Competition - Electric Transmission and Energy Markets in Item 7.

15Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 Form 10-K

Electric Utility Operating Statistics– Other Matters, for more information.

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

SELECTED CONSOLIDATED ELECTRIC UTILITY OPERATING DATA
           
Year Ended December 31 2012 2011 2010 2009 2008
           
Operating Revenues (Millions)          
Residential $1,163.9
 $1,159.2
 $1,114.3
 $977.6
 $962.5
Small Commercial/Industrial 1,013.6
 1,006.9
 922.2
 860.3
 869.7
Large Commercial/Industrial 744.3
 763.7
 677.1
 599.4
 646.3
Other - Retail 22.8
 22.9
 21.9
 21.2
 20.8
Total Retail Revenues 2,944.6
 2,952.7
 2,735.5
 2,458.5
 2,499.3
Wholesale - Other 144.4
 154.0
 134.6
 116.7
 77.7
Resale - Utilities 53.4
 69.5
 40.4
 47.5
 37.7
Other Operating Revenues 51.5
 35.1
 25.8
 62.3
 45.9
Total Operating Revenues $3,193.9
 $3,211.3
 $2,936.3
 $2,685.0
 $2,660.6
           
MWh Sales (Thousands)          
Residential 8,317.7
 8,278.5
 8,426.3
 7,949.3
 8,277.1
Small Commercial/Industrial 8,860.0
 8,795.8
 8,823.3
 8,571.6
 9,023.7
Large Commercial/Industrial 9,710.7
 9,992.2
 9,961.5
 9,140.3
 10,691.7
Other - Retail 154.8
 153.6
 155.3
 156.5
 161.5
Total Retail Sales 27,043.2
 27,220.1
 27,366.4
 25,817.7
 28,154.0
Wholesale - Other 1,566.6
 2,024.8
 2,004.6
 1,529.4
 2,620.7
Resale - Utilities 1,642.4
 2,065.7
 1,103.8
 1,548.9
 881.0
Total Sales 30,252.2
 31,310.6
 30,474.8
 28,896.0
 31,655.7
           
Customers - End of Year (Thousands)          
Residential 1,008.2
 1,005.5
 1,003.6
 1,001.2
 999.1
Small Commercial/Industrial 114.3
 113.8
 113.5
 113.1
 112.6
Large Commercial/Industrial 0.7
 0.7
 0.7
 0.7
 0.7
Other 2.5
 2.5
 2.4
 2.4
 2.4
Total Customers 1,125.7
 1,122.5
 1,120.2
 1,117.4
 1,114.8
           
Customers - Average (Thousands) 1,123.8
 1,121.0
 1,118.7
 1,115.5
 1,111.8
           
Degree Days (a)          
Heating (6,662 Normal) 5,704
 6,633
 6,183
 6,825
 7,073
Cooling (696 Normal) 1,041
 793
 944
 475
 593

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


16Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 Form 10-K

NATURAL GAS UTILITY OPERATIONSSEGMENT

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


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Natural Gas Utility Operating Statistics

The following table shows certain natural gas utility operating statistics for the past three years:
  Year Ended December 31
  2015 2014 2013
Operating revenues (in millions)
      
Residential $256.6
 $390.5
 $296.0
Commercial and industrial 118.9
 204.5
 140.8
Total retail revenues 375.5
 595.0
 436.8
Transport 16.0
 16.8
 16.0
Other operating revenues 8.2
 2.4
 (0.9)
Total $399.7
 $614.2
 $451.9
       
Customers – end of year (in thousands)
      
Residential 438.7
 435.6
 432.1
Commercial and industrial 39.1
 38.9
 38.6
Transport 0.7
 0.6
 0.6
Total customers 478.5
 475.1
 471.3
       
Customers – average (in thousands)
 476.4
 472.6
 469.7

Natural 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, includingtherm deliveries include customer-owned transported gas, were approximately 809.1 million therms during 2012, a 3.4% decrease compared with 2011. As of December 31, 2012, we were transporting gas for approximately 500 customers who purchased gas directly from other suppliers.natural gas. Transported natural gas accounted for approximately 42.6%39.0% of the total volumes delivered during 2012, 35.1%2015, 34.9% during 20112014, and 37.0%35.4% during 2010. We had approximately 468,600 and 466,000 gas customers as of December 31, 2012 and 2011, respectively.2013. Our peak daily send-out during 20122015 was 603,719 Dth7.3 million therms on January 19, 2012.7, 2015.

Sales to Large Natural Gas Customers:   Customers

We provide natural gas utility service to a diversified base of industrial customers who are largely within our electric service territory. Major industries served include the paper,governmental, educational, food products, real estate, and fabricated metal products industries.metal.

Natural Gas Deliveries Growth:Supply, Pipeline Capacity and Storage

We currently forecast total retail therm deliveries (excludinghave been able to meet our contractual obligations with both our suppliers and our customers. For more information on our natural gas deliveriesutility supply and transportation contracts, see Note 15, Commitments and Contingencies.

Pipeline Capacity and Storage

The interstate pipelines serving Wisconsin originate in major natural gas producing areas of North America: the Oklahoma and Texas basins, western Canada and the Rocky Mountains. We have contracted for generation)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 stay flatthe daily and seasonal variations in natural gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage inventory levels at approximately 35% of forecasted winter demand; November through March is considered the winter season. Storage capacity, along with our natural gas purchase contracts, enables us to manage significant changes in daily demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural 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 natural gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.

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

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Term Natural Gas Supply

We have contracts for firm supplies with terms of 3–7 months with suppliers for natural 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 natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our forecasted design peak-day throughput is 9.5 million therms for the 2015 through 2016 heating season.

Secondary Market Transactions

Pipeline long-line and storage capacity and natural gas supplies under contract can be resold in secondary markets. Local distribution companies, like our natural gas operations, must contract for capacity and supply sufficient to meet the firm peak-day demand of their customers. Peak or near peak demand days generally occur only a few times each year. The secondary markets facilitate higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and natural gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to rate payers, subject to our approved GCRM. During 2015, we continued to participate in the secondary markets. For information on our GCRM, see Note 1(d), Revenues and Customer Receivables.

Spot Market Natural Gas Supply

We expect to continue to make natural gas purchases in the spot market as price and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase natural gas in the spot market.

Hedging Natural Gas Supply Prices

We have PSCW approval to hedge up to 60% of planned winter demand and up to 15% of planned summer demand using a mix of NYMEX based natural gas options and futures contracts. This approval allows us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through our GCRM. Hedge targets (volumes) are provided annually to the PSCW as part of our three-year natural gas supply plan and risk management filing.

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

Seasonality

Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to variations in earnings and working capital throughout the year as a result of changes in weather.

Our working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through October. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through October. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the five-year period ending December 31, 2017 as new customer additions are expected to be offset by a reduction in the average use per customer. This forecast reflects a current year weather normalized sales level and normal weather.January through June period.

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 natural gas sales and transportation services to dual-fuel customers. Under natural gas

2015 Form 10-K11Wisconsin Electric Power Company
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transportation agreements, customers purchase natural gas directly from natural gas marketers and arrange with interstate pipelines and us to have the natural gas transported to their facilities. We earn substantially the same margin (difference between revenue and cost of natural gas) whether we sell and transport natural gas to customers or only transport their natural gas.

Our ability to maintain our share of the industrial dual-fuel market depends on our success and the success of third-party natural 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-pricedcompetitively priced transportation service for those customers that desire to buy their own natural gas supplies.

Federal and state regulators continue to implement policies to bring more competition to the natural gas industry. While the natural 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.parties for large commercial and industrial customers. It remains uncertain if and when the current economic disincentives for small firm customers to choose an alternative natural gas commodity supplier may be removed such that we begin to face competition for the sale of natural gas to our smaller firmthose customers.

Gas Supply, Pipeline Capacity and Storage

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

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

17Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 Form 10-K


Due to the daily and seasonal variations in gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage 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:   Capacity release is a mechanism by which pipeline long-line and storage capacity and gas supplies under contract can be resold in the secondary market. Local distribution companies, like our gas operations, must contract for capacity and supply sufficient to meet the firm peak-day demand of their customers. Peak or near peak demand days generally occur only a few times each year. Capacity release facilitates higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to rate payers, subject to our approved Gas Cost Recovery Mechanism (GCRM). During 2012, we continued to participate in the capacity release market. See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 for information on the GCRM.

Spot Market Gas Supply:   We expect to continue to make gas purchases in the 30-day spot market as price 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% planned summer flowing gas supply using a mix of New York Mercantile Exchange (NYMEX) based natural gas options and natural gas future contracts. Those approvals allow us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through our GCRM. Hedge targets (volumes) are provided annually to the PSCW as part of our three-year gas supply plan and risk management filing.

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

18Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 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 2012 2011 2010 2009 2008
           
Operating Revenues (Millions)          
Residential $250.7
 $304.1
 $310.6
 $365.9
 $445.8
Commercial/Industrial 115.4
 149.9
 151.3
 189.7
 238.5
Interruptible 2.3
 2.8
 3.1
 3.5
 6.0
Total Retail Gas Sales 368.4
 456.8
 465.0
 559.1
 690.3
Transported Gas 15.1
 15.0
 14.2
 12.9
 14.3
Other Operating Revenues 1.6
 5.5
 2.4
 (7.8) 4.6
Total Operating Revenues $385.1
 $477.3
 $481.6
 $564.2
 $709.2
           
Therms Delivered (Millions)          
Residential 294.3
 339.4
 321.8
 349.4
 364.7
Commercial/Industrial 165.3
 198.7
 184.5
 208.8
 216.2
Interruptible 5.0
 5.3
 5.5
 5.9
 6.9
Total Retail Gas Sales 464.6
 543.4
 511.8
 564.1
 587.8
Transported Gas 344.5
 294.4
 300.8
 298.4
 313.3
Total Therms Delivered 809.1
 837.8
 812.6
 862.5
 901.1
           
Customers - End of Year (Thousands)          
Residential 429.6
 427.1
 425.6
 423.8
 422.0
Commercial/Industrial 38.5
 38.5
 38.3
 38.2
 38.1
Transported Gas 0.5
 0.4
 0.4
 0.4
 0.4
Total Customers 468.6
 466.0
 464.3
 462.4
 460.5
           
Customers - Average (Thousands) 466.9
 464.7
 462.9
 460.8
 458.3
           
Degree Days (a)          
Heating (6,662 Normal) 5,704
 6,633
 6,183
 6,825
 7,073

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


STEAM UTILITY OPERATIONSSEGMENT

OurWe have a steam utility that generates, distributes, and sells steam supplied by our VAPP and MCPP to customers in metropolitan Milwaukee, County Power Plant.Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. We operate a district steam system in downtown Milwaukee and the near south side of Milwaukee. SteamMilwaukee, and steam is supplied to this system from VAPP, a coal-fired cogeneration facility.VAPP. We also operate the steam production and distribution facilities of the Milwaukee County Power PlantMCPP located on the Milwaukee County Grounds in Wauwatosa, Wisconsin. In 2015, we entered into an agreement to sell the MCPP, which is expected to close during the first half of 2016.

Steam Utility Operating Statistics

Annual sales of steam fluctuate from year to year based uponon system growth and variations in weather conditions. During

2012, theThe following table shows certain steam utility had operating statistics for the past three years:$34.3 million
  Year Ended December 31
  2015 2014 2013
Operating revenues (in millions)
 $41.0
 $44.1
 $39.6
       
Pounds of steam sales (in millions)
 2,515
 2,865
 2,750
       
Customers – Average 430
 440
 445

C. REGULATION

We are subject to the requirements of operating revenues from the salePublic Utility Holding Company Act of 2,449 million pounds2005 as we meet the definition of steam compared with $39.0 milliona holding company under this Act due to our ownership interest in ATC.

In addition to the specific regulations noted below, we are also subject to regulations, where applicable, of operating revenues from the saleEPA, the WDNR, the MDEQ, the Michigan Department of 2,733 million poundsNatural Resources, and the U.S. Army Corps of steam during 2011. As of December 31, 2012Engineers.

Rates
Our rates are regulated by the various commissions shown in the table below. These commissions have general supervisory and 2011, steam was used by approximately 460 customers and 465 customers, respectively, for processing, space heating, domestic hot water and humidification.regulatory powers over public utilities in their respective jurisdictions.
Regulated RatesRegulatory Commission
Retail electric, natural gas, and steamPSCW
Retail electricMPSC
Wholesale powerFERC


2015 Form 10-K1912Wisconsin Electric Power Company
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Embedded within our electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of our symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of our approved fuel and purchased power cost plan. Our deferred fuel and purchased power costs are subject to an excess revenues test. If our ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which our return exceeds the authorized amount.

Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customers and our Wisconsin wholesale electric customers. Our natural gas operations operate under a GCRM as approved by the PSCW. Generally, the GCRM allows for a dollar-for-dollar recovery of prudently incurred natural gas costs.

In May 2015, the PSCW approved the acquisition of Integrys on the condition that we will be subject to an earnings sharing mechanism for three years beginning January 1, 2016. See Note 2, Acquisition, for more information on this earnings sharing mechanism.

For information on how our rates are set, see Note 19, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:
Regulatory CommissionWebsite
PSCW https://psc.wi.gov/
MPSChttp://www.michigan.gov/mpsc/
FERChttp://www.ferc.gov/

The material and information contained on these websites are not intended to be a part of, nor are they incorporated by reference into, this Annual Report on Form 10-K.

The following table compares our utility operating revenues by regulatory jurisdiction for each of the three years ended December 31:
  2015 2014 2013
(in millions) Amount Percent Amount Percent Amount Percent
Electric            
Wisconsin $2,829.5
 82.9% $2,889.9
 85.0% $2,874.8
 86.9%
Michigan 163.0
 4.8% 58.8
 1.7% 147.0
 4.4%
FERC – Wholesale 329.5
 9.6% 396.0
 11.6% 286.9
 8.7%
FERC – SSR * 91.4
 2.7% 56.4
 1.7% —
 —%
Total 3,413.4
 100.0% 3,401.1

100.0% 3,308.7
 100.0%
             
Natural Gas – Wisconsin 399.7
 100.0% 614.2
 100.0% 451.9
 100.0%
             
Steam – Wisconsin 41.0
 100.0% 44.1
 100.0% 39.6
 100.0%
             
Total utility operating revenues $3,854.1
 

 $4,059.4
 

 $3,800.2
 


*See Note 19, Regulatory Environment, for more information regarding SSR revenues.

Electric Transmission, Capacity, and Energy Markets

In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which include 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.


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UTILITY RATE MATTERSIn MISO, base transmission costs are currently being paid by load-serving entities located in the service territories of each MISO transmission owner. The 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.

See Factors Affecting Results, LiquidityAs 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 Capital Resources -- Ratesmid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through ARRs and Regulatory Matters in Item 7.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, 2015 through May 31, 2016. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.


REGULATIONBeginning June 1, 2013, MISO instituted an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources could be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. Our capacity requirements during 2015 were fulfilled using our own capacity resources.

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

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

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

The following table compares our operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2012:

  2012 2011 2010
  Amount Percent Amount Percent Amount Percent
  (Millions of Dollars)
Electric            
Wisconsin - Retail $2,808.4
 87.9% $2,775.8
 86.4% $2,568.3
 87.5%
Michigan - Retail 187.8
 5.9% 212.0
 6.6% 193.0
 6.6%
FERC - Wholesale 197.7
 6.2% 223.5
 7.0% 175.0
 5.9%
Total 3,193.9
 100.0% 3,211.3
 100.0% 2,936.3
 100.0%
             
Gas - Wisconsin - Retail 385.1
 100.0% 477.3
 100.0% 481.6
 100.0%
             
Steam - Wisconsin - Retail 34.3
 100.0% 39.0
 100.0% 38.8
 100.0%
Total Utility Operating Revenues $3,613.3
 

 $3,727.6
 

 $3,456.7
 


Our operations are also subject to regulations, where applicable, of the United States Environmental Protection Agency (EPA), the Wisconsin Department of Natural Resources (WDNR), the Michigan Department of Environmental Quality 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. Underand Public Act 141, we must meet295 in Michigan, which contain certain minimum requirements for renewable energy generation. ForSee Note 15, Commitments and Contingencies, for more information.

All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Other Natural Gas Regulations

Almost all of the years 2010 through 2014,natural gas we must increasedistribute is transported to our percentagedistribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of total retail energy sales provided by renewable sources (renewable energy percentage) by at least two percentage points from

20Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2012 Form 10-K

our baseline renewable percentage of 2.27% to a level of 4.27%. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. As of December 31, 2012, 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%.1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the state commissions are responsible for monitoring and enforcing requirements governing our natural gas safety compliance programs for our pipelines under this Act, 1.2%United States Department of utilities' annual operating revenues wereTransportation regulations. These regulations include 49 Code of Federal Regulations (CFR) Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards) and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

We are required to be usedprovide natural gas service and grant credit (with applicable deposit requirements) to fund energy conservationcustomers within our service territory. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs in 2012. Thethat provide for a limited amount of funding required by Act 141 for 2013 is also 1.2% of annual operating revenues.

Public Act 295 enacted in Michigan requires 10% of the state's energyassistance 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.

For additional information on Act 141 and current renewable projects, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters - Renewables, Efficiency and Conservation and Rates and Regulatory Matters - Renewable Energy Portfolio in Item 7.

our low-income customers.

D. ENVIRONMENTAL COMPLIANCE

Our operations are subject to extensive environmental regulationsregulation 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 gasGHG 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 the estimated capital expenditures described in Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources 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 MattersRequirements in Item 7. For a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites, and air and water quality, see Note P --15, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.

Compliance with federal, state and local environmental protection requirements resulted in capital expenditures of approximately $64.1 million in 2012 compared with $120.3 million in 2011. Expenditures incurred during 2012 and 2011 primarily included costs associated with the installation of pollution abatement facilities at our power plants. These expenditures are expected to be approximately $22 million during 2013, reflecting the addition of control equipment for Nitrogen Oxide (NOx), Sulfur Dioxide (SO2) and other pollutants needed to comply with various rules promulgated by the EPA and the Consent Decree entered into with the EPA in 2003. Operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $82.6 million and $79.0 million during 2012 and 2011, 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 impacts identified near the sites, located in the Village of Caledonia and the City of Oak Creek, Wisconsin, prompted us to begin investigation in 2009 for the source of impacts found in monitoring wells on the site and surrounding area. Our study indicates that the groundwater impacts may be naturally occurring or are from other sources based on groundwater flow direction and increasing concentrations of

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elements deeper in the ground. The WDNR began sampling work in 2011 to identify the sourceContingencies, and Management's Discussion and Analysis of the groundwater impactsFinancial Condition and issued its report on January 24, 2013. The WDNR study found that the data was inconclusive as to the source causing the groundwater impacts. We reviewed the WDNR reportResults of Operations – Factors Affecting Results, Liquidity, and provided technical comments on February 18, 2013 further supporting our position that regional ground water impacts are not a result of coal ash management activities at the Oak Creek site.


See Item 3 Legal Proceedings --Capital Resources – Environmental Matters for a discussion of the bluff collapse at our Oak Creek Power Plant.

in Item 7.

OTHERE. EMPLOYEES

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


Employees:As of December 31, 2012,2015, we had 4,054 total3,653 employees, of which 2,6603,551 were full-time. Effective January 1, 2016, approximately 485 of our employees were transferred into WBS. See Note 3, Related Parties, for more information on WBS and the services it provides.

As of December 31, 2015, we had employees represented under labor agreements with the following bargaining units:

  Number of Employees Expiration Date of Current Labor Agreement
Local 2150 of International Brotherhood of Electrical Workers, AFL-CIO 1,8291,679
 August 15, 20132017
Local 420 of International Union of Operating Engineers, AFL-CIO 554489
 March 31, 2013 September 30, 2017
Local 2006 Unit 51 of United Steel Workers of America, AFL-CIO 161123
 October 31, 2013  April 30, 2017
Local 510 of International Brotherhood of Electrical Workers, AFL-CIO 116105
 April 30, 2013October 31, 2016
Total 2,6602,396
  



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2012 Form 10-K

ITEM 1A.RISK FACTORS
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 the Operation of Our BusinessLegislation 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 the regulation, ofincluding regulation by the PSCW, asMPSC, and FERC. This regulation significantly influences our operating environment and may affect our ability to recover costs from utility customers. Many aspects of our operations are regulated, including, but not limited to: the rates we charge our retail electric, natural 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 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. Further, our hydroelectric facilities are regulated by FERC, and FERC also regulates ourcustomers; wholesale power service practices,practices; electric reliability requirements and accounting; participation in the interstate natural gas pipeline capacity market.market; standards of service; issuance of securities; short-term debt obligations; construction and operation of facilities; transactions with affiliates; and billing practices. 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 Failure to comply with any applicable rules or regulations whether through new interpretations or applications of the regulations or otherwise, we may be liable forlead to customer refunds, penalties, and other amounts,payments, which could materially and adversely affect our results of operations and financial condition.

We estimate that approximately 88%The rates we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of our electric revenues are regulated by the PSCW, 6% are regulated by the MPSCoperations, and the balanceliquidity. 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 electric revenues is regulated by FERC. All of our natural gas and steam revenues are regulated by the PSCW. Our ability to obtain rate adjustments in the future is dependent uponon regulatory action, and there can beis no assurance that weour regulators will be ableconsider all of our costs to obtainhave been prudently incurred. In addition, our rate adjustmentsproceedings may not always result in the futurerates that will allow us tofully recover our costs or provide for a reasonable ROE. We defer certain costs and expensesrevenues as regulatory assets and liabilities for future recovery or refund to maintaincustomers, 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 recognized in current authorized ratesperiod expense and could have a material adverse impact on our results of return.operations, cash flows, and financial condition.

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

Governmental agencies could modify our permits, authorizations or licenses.

We are required to comply with the terms of various permits, authorizations and licenses.laws. These permits, approvals, authorizations, certificates, 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. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies. Changes in regulations, interpretations of regulations, or the imposition of new regulations could influence our operating environment, may result in substantial compliance costs, or may require us to change our business operations.

Also, ifIf we are unable to obtain, renew, or comply with these governmental permits, approvals, authorizations, certificates, or licenses, or if we are unable to recover any increased costs of complying with additional license requirements or any other associated costs in ourcustomer rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.

FactorsWe may face significant costs to comply with existing and future environmental laws and regulations.

Our operations are subject to numerous federal and state environmental laws and regulations. These laws and regulations govern, among other things, air emissions (including CO2, methane, mercury, SO2, and NOx), water quality, wastewater discharges, and management of hazardous, toxic, and solid wastes and substances. We incur significant costs to comply with these environmental requirements, including costs associated with the installation of pollution control equipment, environmental monitoring, emissions fees, and permits at our facilities. In addition, if we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, could adversely affect project coststhat failure may result in the assessment of civil or criminal penalties and completion of construction projects.fines.

We areThe EPA has adopted and has implemented (or is in the process of constructing new renewable generation, includingimplementing) regulations governing the biomass facility in Rothschild, Wisconsin. These typesemission of construction projects are subject to usual construction risks over which we will have limited or no controlNOx, SO2, fine particulate matter, mercury, and which might adversely affect project costsother air pollutants under the CAA through the NAAQS, the MATS rule, the Clean Power Plan, the CSAPR, and completion time. These risks include, but are not limited to, shortages of,other air quality regulations. In addition, the ability to obtain orEPA has finalized regulations under the cost of labor or materials; the ability of the contractors to perform under their contracts; strikes; adverse weather conditions; the ability to obtain necessary operating permits in a timely manner; legal challenges; changes in applicable law or regulations; adverse interpretation or enforcement of permit conditions, laws and regulations by courts or the permitting agencies; other governmental actions; and events in the global economy.Clean Water Act that govern

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cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA has also adopted a final rule that would expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters; however, this rule has been stayed. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. Several environmental regulations were either finalized or implemented during 2015, and there is still uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with these regulations.

Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level that could result in significant additional expenditures for our generation units or distribution systems, including, without limitation, costs to further limit GHG emissions from our operations through emission control technology; operating restrictions on our facilities; and increased compliance costs. In addition, the operation of emission control equipment and compliance with rules regulating our intake and discharge of water could increase our operating costs and reduce the generating capacity of our power plants. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels.

As a result, certain of our coal-fired electric generating facilities may become uneconomical to maintain and operate, which could result in some of these units being retired early or converted to an alternative type of fuel. If generation facility owners in the Midwest, including us, are forced to retire a significant number of older coal-fired generation facilities, a potential reduction in the region's capacity reserve margin below acceptable risk levels may result. This could impair the reliability of the grid in the Midwest, particularly during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.

We are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities, and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation, and related legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other third parties. Due to the potential for imposition of stricter standards and greater regulation in the future, as well as 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 or could vary from the amounts currently accrued.

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.

Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, has increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by environmental impacts and alleged exposure to hazardous materials have become more frequent. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of facilities that we previously owned and operated, regardless of whether the liabilities arose before, during, or after the time we owned or operated these facilities. If we fail to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.

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

Federal, state, regional, and international authorities have undertaken efforts to limit GHG emissions. In 2015, the EPA issued the Clean Power Plan, which is a final rule that regulates GHG emissions from existing generating units, as well as a proposed federal plan as an alternative to state compliance plans. The EPA also issued final performance standards for modified and reconstructed generating units, as well as for new fossil-fueled power plants. Under the Clean Power Plan, states are required to submit compliance plans as early as September 2016 to achieve state-specific GHG emission reductions by 2030. If Wisconsin or Michigan determines not to file a state compliance plan, we may be required to comply with the federal plan, which could result in more significant compliance costs than a state compliance plan. We are continuing to analyze the final rule and to work with other stakeholders to

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determine how to implement the Clean Power Plan and the potential impacts to our operations. In October 2015, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals) denied the stay request, but on February 9, 2016, the United States Supreme Court (Supreme Court) stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. Therefore, it is unlikely that states will move forward on the development of the state plans until the litigation is complete. Any state or federal compliance plans that are developed could be subject to change based upon the outcome of this litigation. In addition, on February 15, 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The rule could result in significant additional compliance costs, including capital expenditures, and impact how we operate our existing fossil-fueled power plants and biomass facility, all of which could have a material adverse impact on our operating costs.

If we are unable to complete the development or construction of a facility or decide to delay or cancel construction, we may not be able to recover our investment in the facility and may incur substantial cancellation payments under equipment and construction contracts. Even if a construction project is completed, the total costs may be higher than estimated and/or higher than amounts approved by our regulators, and thereThere is no guarantee that we will be allowed to fully recover costs incurred to comply with the Clean Power Plan or that cost recovery will not be delayed or otherwise conditioned. The Clean Power Plan and any other related regulations that may be adopted in the future, either at the federal or state level, may cause our environmental compliance spending over the next several years to differ materially from the amounts currently estimated. These regulations could have a material adverse impact on our electric generation and natural gas distribution operations, could make some of our electric generating units uneconomic to maintain or operate, and could affect unit retirement and replacement decisions. These regulations could also adversely affect our future results of operations, cash flows, and financial condition.

In addition, our natural gas delivery systems may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair of natural gas delivery systems. Fugitive gas typically vents to the atmosphere and consists primarily of methane. CO2 is also a byproduct of natural gas consumption. As a result, future legislation to regulate GHG emissions could increase the price of natural gas, restrict the use of natural gas, and adversely affect our ability to operate our natural gas facilities. A significant increase in the price of natural gas may increase rates for our natural gas customers, which could reduce natural gas demand.

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

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

Risks Related to the Operation of Our Business

Our operations are subject to risks arising from the reliability of our electric generation, transmission, and distribution facilities, natural gas infrastructure facilities, and other facilities, as well as the reliability of third-party transmission providers.

Our financial performance depends on the successful operation of our electric generation and natural gas and electric distribution facilities. The operation of these facilities involves many risks, including operator error and the breakdown or failure of equipment or processes. Potential breakdown or failure may occur due to severe weather; catastrophic events (i.e., fires, earthquakes, explosions, tornadoes, floods, droughts, pandemic health events, etc.); significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; shortages of or delays in obtaining equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; or cyber security threats. Any of these events could lead to substantial financial losses.

Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues or cause us to incur significant costs in rates. Construction delays can alsoif we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.

Insurance, warranties, performance guarantees, or recovery through the delayregulatory process may not cover any or all of these lost revenues and, therefore,or increased expenses, which could adversely affect our results of operations.operations and cash flows.

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In addition, construction delays at our biomass facility currently under construction couldOur operations are subject to various conditions that can result in the loss of a cash grant we expectfluctuations in energy sales to receive pursuant to the National Defense Authorization Act (NDAA). The PSCW included the anticipated proceeds from this grant when it set our retail electric rates in the 2013 rate case, thereby reducing the amounts collected directly from our customers.

We have announced plans to upgrade our electriccustomers, including customer growth and natural gas distribution systems. Although these projects are smaller in scope than the above referenced construction projects, they are still subject to many of the same risks and challenges.

Customer growthgeneral economic conditions in our service areas, affects our results of operations.varying weather conditions, and energy conservation efforts.

Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:

Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be affectednegatively impacted by population growthdeclines as well as economic factors in Wisconsinour service territories, including job losses, decreases in income, and business closings. We are impacted by economic cycles and the Upper Peninsulacompetitiveness of Michigan, including jobthe commercial and income growth. Customer growthindustrial customers we serve. Any economic downturn or disruption of financial markets could adversely affect the financial condition of our customers and demand for their products. These risks could directly influencesinfluence the demand for electricity and natural gas andas well as the need for additional power generation and generating facilities. Population declines and/or business closings in our service territories or slower than anticipated customer growth has a negative impact on our results of operations and cash flow andWe could expose usalso be exposed 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 weatherWeather 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. Mildmilder temperatures during the summer cooling season and during the winter heating season will negatively impactmay result in lower revenues and net income.
Our customers' continued focus on energy conservation and ability to meet their own energy needs. Customers could voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, and individual conservation efforts through the resultsuse of operationsmore energy efficient technologies. Conservation of energy can be influenced by certain federal and cash flowsstate programs that are intended to influence how consumers use energy. In addition, several states, including Wisconsin and Michigan, have adopted energy efficiency targets to reduce energy consumption by certain dates.

As part of our electric utility business. In addition, mild temperatures duringplanning process, we estimate the winter heating season negatively impact the resultsimpacts of operationschanges in customer growth and cash flowsgeneral economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of our gas utility business.

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,these matters, 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 coal- and natural gas-fired 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 orregulatory delay in recoveryadjusting rates as a result of any such costsreduced sales from effective conservation measures or the adoption of new technologies, could adversely affectimpact our results of operations and cash flows.financial condition.

In addition, damages resulting from severe weather events withinWe are actively involved with several significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our service territories may result in the loss of customers and reduced demand for electricityelectric generating facilities, electric and natural gas distribution infrastructure, natural gas storage, and other projects, including projects for extended periods. Any significant lossenvironmental compliance.

Achieving the intended benefits of customersany large construction project is subject to many uncertainties, some of which we will have limited or reduction in demandno control over, that could adversely affect project costs and completion time. These risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy. In addition, certain of these projects require the approval of our regulators. If construction of commission-approved projects should materially and adversely deviate from the schedules, estimates, and projections on which the approval was based, the applicable commission may deem the additional capital costs as imprudent and disallow recovery of them through rates.

To the extent that delays occur, costs become unrecoverable, or we otherwise become unable to effectively manage and complete our capital projects, our results of operations, cash flows, and cash flows.financial condition may be adversely affected.

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

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, and energy efficiency. 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 production. If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities could be

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Our financial performance may be adversely affected if we are unable to successfully operatereduced. Advances in technology could also change the channels through which our facilities.electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.

Our financial performance depends on the successful operationoperations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of our electric generating and gas distribution facilities. Operation of these facilities involves many risks, including: operator error and breakdownwar, or failure of equipment processes; fuel supply interruptions; labor disputes; operating limitations that may be imposed by environmental or other regulatory requirements; 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.

An increase in natural gas costs could negatively impact our electric and gas utility operations.unauthorized access to personally identifiable information.

We burnface the risk of terrorist and cyber intrusions, both threatened and actual, against our generation facilities, electric and natural gas in several ofdistribution infrastructure, our peaking power plantsinformation and in Port Washington Generating Station Unit 1 (PWGS 1)technology systems, and Port Washington Generating Station Unit 2 (PWGS 2), and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. Disruption in the supply of natural gas due to a curtailment in production or distribution can increase the cost of natural gas, as can international market conditions and demand for natural gas. 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.

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

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

We are dependent on coal for much of our electric generating capacity. Although we currently have an adequate supply of coal at our coal-fired facilities, there can be no assurancenetwork infrastructure, including that we will continue to have an adequate supply of coal in the future. 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. The suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to us. 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, international demand for coal can impact its availability and cost. If we significantly reduce our inventory of coal and 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 Energy Markets.

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 targetsany of terrorist activities. A terrorist attack on our facilities (or those of third parties)which 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, financial condition, and financial condition.

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.cash flows.

We operate in an industry that requires the continued operationuse of sophisticated information technology systems and network infrastructure, which are part ofcontrol an interconnected regionalsystem of generation, distribution, and transmission grid. In addition, in the ordinary course of business,systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we collectrequire our vendors to take, which include compliance with reliability standards and retain sensitive information including personal information about our customers and employees.


25Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2012 Form 10-K

Cybercritical infrastructure protection standards. Successful cyber intrusions, including those targeting the electronic control systems used at our generating facilities and for the electric and natural gas transmission, distribution, and storage systems, could disrupt our operations and 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 acustomers. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant decrease in revenues, as well as significant expensecosts if we are required to repair system damage and remedy security breaches. Furthermore, we may need to obtain more expensive purchasedoperate our higher cost electric generators or purchase replacement power to meet customer demand for electricity ifsatisfy our electric generating facilities are unable to operate at full capacityobligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.

We face on-going threats to our assets and technology systems. Despite the implementation of strong security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to human error or physical or cyber intrusions. If our assets or systems were to fail, be physically damaged, or be breached and were not recovered in a cyber intrusion. Any resultingtimely manner, we may be unable to perform critical business functions, and sensitive and other data could be compromised.

Our business requires the collection and retention of personally identifiable information of our customers and employees, who expect that we will adequately protect such information. Security breaches may expose us to a risk of loss or misuse of revenueconfidential and proprietary information. A significant theft, loss, or increase in expensefraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could have a material adverse effect oncause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact 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.

Internet-based attacks on critical U.S. energy infrastructure are occurring with more frequency. On February 12, 2013, 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 to be developed jointly by the government and industry. As cyber attacks become more sophisticated generally and/or as this framework is implemented, In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems from outside intrusions and/orsystems. We may also need to obtain additional insurance coverage related to the threat of such attacks.intrusions.

We couldThe costs of repairing damage to our facilities, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may not be subject to higher costs and penalties as a result of mandatory reliability standards.recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.

WeTransporting, distributing, and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.

Inherent in natural gas distribution activities are subjecta variety of hazards and operational risks, such as leaks, accidental explosions, including third party damages, and mechanical problems, which could materially and adversely affect our results of operations, financial condition, and cash flows. In addition, these risks could result in serious injury to mandatory reliabilityemployees and critical infrastructure protection standards established bynon-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of natural gas pipelines and storage facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the North American Electric Reliability Corporation. The critical infrastructure protection standards focus on controlling access to critical and physical and cybersecurity assets. Compliance with the mandatory reliability standards couldlevel of damages resulting from these risks. These activities may subject us to higher operating costs. If we are foundlitigation or administrative proceedings from time to betime, which could result in noncompliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.judgments, fines, or penalties against us, or be resolved on unfavorable terms.


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


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

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

We operate in an industry that requires many of our employees to possess a unique technical skill set.sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. 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.

Work stoppages or increased labor costs could adversely affect our operations and financial condition.

As of December 31, 2012, we had 4,054 total employees, of which 2,660 or approximately 66% are represented by labor unions. AllFailure of our laborcounterparties to meet their obligations, including obligations under power purchase agreements, are scheduled to expire in 2013. We expect that rising healthcare, pension and wage costs, among other things, will be important topics for negotiation. It is important for us to control healthcare, pension and wage costs provided for in the labor agreements, or we risk increased operational costs. If we are unable to negotiate acceptable contracts with these unions, we could be subject to strikes, work stoppages or other slowdowns by the affected workers. These actions could disrupt our operations and have an adverse impact on our results of operations.

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.

We have entered into several power purchase agreements with non-affiliated companies, and continue to look for additional opportunities to enter into these agreements. 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 delay in adjusting 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.

The 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. 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 credit and capital markets to support our 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, on competitive terms and rates. In addition, we rely on a committed bank credit agreement as back-up liquidity, which allows us to access the low cost commercial paper markets.

Our access to the credit and capital markets could be limited, or our cost of capital significantly increased, due to any of the following risks and uncertainties:

A rating downgrade;
An economic downturn or uncertainty;

2015 Form 10-K2621Wisconsin Electric Power Company
Table of Contents

Prevailing market conditions;
Concerns over foreign economic conditions;
Changes in tax policy;
War or the threat of war; and
The overall health and view of the utility and financial institution industries.

If any of these risks or uncertainties limit our access to the credit and capital markets or significantly increase our cost of capital, it could limit our ability to implement, or increase the costs of implementing, our business plan, which, in turn, could materially and adversely affect our results of operations, cash flows, and financial condition.

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

There are a number of factors that impact our credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We could experience a downgrade in our ratings if the rating agencies determine that the level of business or financial risk of us or the utility industry has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings.

Any downgrade by the rating agencies could:

Increase borrowing costs under our existing credit facility;
Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;
Decrease funding sources by limiting our access to the commercial paper market;
Limit the availability of adequate credit support for our operations; and
Trigger collateral requirements in various contracts.

Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.

Our margins and liquidity requirements are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.

We burn natural gas in several of our electric generation plants, 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. The cost of natural gas may increase because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations affecting its accessibility.

For Wisconsin customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical 2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Our natural gas operations receive dollar-for-dollar recovery of prudently incurred natural gas costs.

Changes in commodity prices could result in:

Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;
Reduced profitability to the extent that reduced margins, increased bad debt, and interest expense are not recovered through rates;
Higher rates charged to our customers, which could impact our competitive position;
Reduced demand for energy, which could impact margins and operating expenses; and
Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

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 protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure 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

ITEM 1A. RISK FACTORS - (Cont'd)20122015 Form 10-K22Wisconsin Electric Power Company
Table of Contents

onfulfill 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 financial conditioncoal 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-fired units and replace this lost generation through additional power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed, either of which could adversely affect our cash flows.

Our electric generation frequently exceeds our customer load. When this occurs, we generally sell the excess generation into the MISO Energy Markets. 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.price exposure. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although our hedging programs must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.

The Dodd-Frank Act, enacted in July 2010, provides for the regulation of derivatives and grants the CFTC expanded regulatory authority over derivative and swap transactions. The CFTC has promulgated numerous regulations that will impose additional requirements on the use of derivatives and swap transactions for us and our counterparties, which could affect both the use and cost of these instruments. Several of the rules still need to be finalized, pending the CFTC's requests for further comments on certain interim rules, interpretations and proposed exemptions, and requests for clarifications by several interested parties. Although we cannot be certain of the impact of these new rules on us until these matters are fully resolved, we currently do not expect it to be material.

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.

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 which allowschoice. Under Michigan law, our retail customers to remain with their regulated utility at regulated rates ormay choose an alternative electric supplier to provide power supply service. WeThe law limits customer choice to 10% of our Michigan retail load. The two iron ore mines in the Upper Peninsula of Michigan are excluded from this cap. When a customer switches to an alternative electric supplier, we continue providingto provide distribution and customer service functions regardless offor the customer's power supplier. Although competition and customer switching to alternative supplierscustomer. It is uncertain whether retail choice might be implemented in our service territories in Michigan has been limited, the additional competitive pressures resulting from retail access could lead to a loss of customers and our incurring stranded costs. A loss of customers could also have a material adverse effect on our results of operations and cash flows.Wisconsin.

FERC continues to support the existing RTOs that affect the structure of the wholesale market within thosethese 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)an 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 Marketancillary services market for operating reserves that was simultaneously co-optimized with its existing energy markets.

These market designs continue to have the potential to increase the costs of transmission, the costs associated with inefficient

27Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2012 Form 10-K

generation dispatching, the costs of participation in the marketMISO Energy Markets, and the costs associated with estimated payment settlements.

Risks RelatedWe may experience poor investment performance of benefit plan holdings due to Legislationchanges in assumptions and Regulationmarket conditions.

We may facehave 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), SO2, NOx, 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. In April 2003, we reached a Consent Decree with the EPA to significantly reduce air emissions from our coal-fired generating facilities. Through the end of 2012, we had invested approximately $1.2 billion to comply with the Consent Decree. We estimate we will spend an additional $22 million in 2013 for final implementation costs.

We will be required to be in compliance with environmental regulations that become effective over the next several years, including the EPA's Mercury and Air Toxics Standards (MATS) rule, new SO2 and Nitrogen DioxideNational Ambient Air Quality Standards and new emission limits on fine particulate matter (PM2.5), as well as rulesobligations related to cooling water intake structures atpension and OPEB plans. If WEC Energy Group is unable to successfully manage benefit plan assets and our power plants. In addition, the EPA adopted the Cross-State Air Pollution Rule (CSAPR), which provides for limits on the interstate transport of NOx and SO2 emissions. The U.S. Court of Appeals for the D.C. Circuit vacated the CSAPR. The EPA had requested the Court to re-hear the case; however, on January 24, 2013 the court denied the EPA's request. The EPA may still appeal this decision to the United States Supreme Court. Therefore, there is still substantial uncertainty as to what capital expenditures may ultimately be required to comply with these regulations. In the meantime, the Clean Air Interstate Rule (CAIR) remains in effect.

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 entered a joint ownership agreement with Wolverine regarding PIPP, whereby, subject to the approval of various state and federal agencies, Wolverine will pay for the installation of environmental upgrades at the plant and will receive a minority ownership interest in the plant in return. In addition, we announced plans to convert the fuel source for VAPP from coal to natural gas at an expected cost of between $60 million and $65 million. These and other compliancemedical 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 regulations may be revisedour cash flows, financial condition, 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 notices of violation to us alleging violations of certain environmental rules. An adverse outcome in these matters could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial 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.

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)2012 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.

Energy conservation and rate increases could negatively impact financial results.

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.

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 earliest the EPA will take action on this matter is the first quarter of 2014.

In addition, the EPA finalized the Commercial and Industrial Solid Waste Incineration Units rule under the Clean Air Act (CAA), and finalized a Non-Hazardous Secondary Materials Rule. Both of these rules have the potential to negatively affect our ability to reburn coal ash from power plants and landfills.

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

The President's administration recently reaffirmed that the regulation of greenhouse gas emissions continues to be a top priority. Legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards has failed to pass in the U.S. Congress; however, we expect such legislation to be considered in the future. Although we cannot currently predict with any certainty what form these future regulations will take, the stringency of the regulations or when they will become effective, we do believe that future governmental legislation and/or regulation may require us to limit or control greenhouse gas emissions from our operations, purchase allowances for such emissions or otherwise incur costs in connection with such emissions.

While climate legislation has yet to be adopted, the EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. In March 2010, the EPA issued regulations governing the applicability of the CAA's permitting requirements for greenhouse gas emissions to power plants and other commercial and industrial facilities. These rules became applicable to sources that are already subject to CAA permitting requirements, as well as new and modified sources, during 2011. In March 2012, the EPA proposed new source performance standards pertaining to greenhouse gas emissions from certain new power plants, including coal-fired plants, based on the performance of combined cycle natural gas-fueled generating plants. We believe this rule effectively prohibits new conventional coal-fired power 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. We expect the EPA to attempt to address performance standards for existing generating units in 2013. Any such regulations may impact how we operate our existing facilities.

Legislation to regulate greenhouse gas emissions and establish renewable and efficiency standards has also been

29Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2012 Form 10-K

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 future legislation, regulation or order that requires a reduction in greenhouse gas emissions or that cost recovery will not be delayed or otherwise conditioned. Any future legislation or regulation that may be adopted, either at the federal or state level, designed 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 continue to monitor the legislative, regulatory and legal developments in this area.

Risks Related to Economic and Market Volatility

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

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

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 continue to experience electric and natural gas sales below historical trends.

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 benefitthese plans is dependent upon a number of factors, including actual plan experience, changes made to the plans, and assumptions concerning the future, such asfuture. Types of assumptions include 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, estimated withdrawals by retirees, 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 as experienced in prior periodsIn addition, medical costs for both active and retired employees may increase our funding requirements. Changes in interest rates

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ITEM 1A. RISK FACTORS - (Cont'd)2012 Form 10-K

affect plan liabilities - as rates decrease, the liabilities increase, which could increase our funding requirements. Changes in demographics, such as an increase in the number of retirements or changes in life expectancy assumptions, may also increase our funding requirements. Changes made to the plans may also impact current and future pension costs. 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 benefitcurrently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, and medical costs, our cash flows, financial conditionchanges in interest rates, changes in demographics (including the number of retirements) or results of operations could be adversely impacted.changes in life expectancy assumptions.

Our abilityWe may be unable to obtain insurance on acceptable terms or at all, 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 coveragewe do obtain 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 bybusiness; international, national, state, or local events, as well asevents; and 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. A loss for which we are not fully insured could have a material adverse effect on our results of operations. 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, orand financial condition.position.

Risks Related to the Integrys Acquisition

The acquisition of Integrys may not achieve its anticipated results, and WEC Energy Group may be unable to integrate operations as expected.
The Merger Agreement was entered into with the expectation that the acquisition would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, including whether the businesses of WEC Energy Group can be integrated in an efficient, effective, and timely manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees; the disruption of ongoing businesses, processes, and systems; or inconsistencies in standards, controls, procedures, practices, policies, and compensation arrangements, any of which could adversely affect WEC Energy Group's ability to achieve the anticipated benefits of the transaction as and when expected. WEC Energy Group may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve the anticipated benefits of the acquisition could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results, and prospects.

ITEM 1B.UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS

None.



2015 Form 10-K24Wisconsin Electric Power Company
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ITEM 2.PROPERTIES
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 natural gas utility distribution mains and services are located, for the most part, on or under streets and highways and on land owned by others and are generally subject to granted easements, consents or permits. In addition, we lease the PTF generating units.

31Wisconsin Electric Power Company
ITEM 2. PROPERTIES - (Cont'd)2012 Form 10-K



As of December 31, 2012,2015, we owned, or leased from We Power, the following generating stations:

assets:
 No. of Dependable
 Generating Capability
Name Fuel Units In MW (a) Location Fuel Number of Generating Units 
Rated Capacity In MW (1)
 
Coal-Fired Plants    
Coal-fired plants     
Milwaukee County Wauwatosa, WI Coal 3
 7
(2) 
Oak Creek Expansion Oak Creek, WI Coal 2
 1,057
(3) 
Pleasant Prairie Pleasant Prairie, WI Coal 2
 1,188
 
Presque Isle Marquette, MI Coal 5
 344
 
South Oak Creek Coal 4
 976
 Oak Creek, WI Coal 4
 993
 
Oak Creek Expansion Coal 2
 1,057
Presque Isle Coal 5
 344
Pleasant Prairie Coal 2
 1,188
Valley Coal 2
 256
Milwaukee County Coal 3
 7
Total Coal-Fired Plants 18
 3,828
Total coal-fired plants 16
 3,589
 
Natural gas-fired plants     
Concord Combustion Turbines Watertown, WI Natural Gas/Oil 4
 352
 
Germantown Combustion Turbines Germantown, WI Natural Gas/Oil 5
 258
 
Paris Combustion Turbines Union Grove, WI Natural Gas/Oil 4
 352
 
Port Washington Generating Station Port Washington, WI Natural Gas 2
 1,082
 
Valley Power Plant Milwaukee, WI Natural Gas 2
 240
 
Total natural gas-fired plants 17
 2,284
 
Renewables     
Hydro Plants (13 in number) 33
 40
 WI Hydro 33
 86
 
Port Washington Generating Station Gas 2
 1,090
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
 —
Rothschild Biomass Plant Rothschild, WI Biomass 1
 50
 
Blue Sky Green Field Fond du Lac, WI Wind 88
 21
 
Byron Wind Turbines Wind 2
 —
 Fond du Lac, WI Wind 2
 —
 
Blue Sky Green Field Wind 88
 29
Glacier Hills Wind 90
 32
 Cambria, WI Wind 90
 28
 
Montfort Wind Energy Center Wind 20
 6
 Montfort, WI Wind 20
 2
 
Total System 268
 5,987
Total renewables     234
 187
 
Total system     267
 6,060
 

(a)
(1)
Dependable capabilityBased on expected capacity ratings for summer 2016, which can differ from nameplate capacity, especially on wind projects. The summer period is the net power output under average operating conditions with equipmentmost relevant for capacity planning purposes. This is a result of continually reaching demand peaks in an average statethe summer months, primarily due to air conditioning demand.

(2)
We expect to complete the sale of repair asthe MCPP during the first half of a given month in a given year.2016.

(3)
This facility is jointly owned by We are a summer peaking electric utility.Power and various other utilities. The values are established by tests and may change slightly from yearcapacity indicated for the facility is equal to year.We Power's portion of total plant capacity based on its 83.34% ownership.

As of December 31, 2012,2015, we operated approximately 21,55121,500 pole-miles of overhead distribution lines and 23,91224,400 miles of underground distribution cable, as well as approximately 350366 distribution substations and 289,826approximately 298,900 line transformers.

As of December 31, 2012,2015, our natural gas distribution system included approximately 9,4689,700 miles of distribution mains connected at 2628 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, Northern Natural Pipeline Company and Great Lakes Transmission Company.Company, and approximately 407,000 natural gas lateral services. We have a liquefied natural gas storage plant that converts and stores, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plant has a send-out capability of 70,000 Dth per day. Our natural gas distribution system consists almost entirely of plastic and coated steel pipe.

We also own office buildings, natural 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 natural gas distribution mains and

2015 Form 10-K25Wisconsin Electric Power Company
Table of Contents

services occupy private property, we have in some, but not all instances, obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.

As of December 31, 2012,2015, the combined steam systems supplied by the VAPP and Milwaukee County Power Plant consisted of approximately 4342 miles of both high pressure and low pressure steam piping, nine miles of walkable tunnels and other pressure regulating equipment.


32Wisconsin Electric Power Company
2012 Form 10-K

ITEM 3.LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS

In addition to those legal proceedings discussed below,in this Annual Report on Form 10-K, 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.

Bluff Collapse:  On October 31, 2011, a portion of the bluff at our Oak Creek Power Plant collapsed. The affected area, located south of the new Air Quality Control System (AQCS), was a former ravine that had been filled with coal ash prior to the advent of landfill regulations. Following the receipt of permits and approvals from the WDNR, bluff reconstruction and stabilization were completed in November 2012. We received final spill closure related to our rework of the storm water management infrastructure from the WDNR on December 10, 2012, following submission of environmental studies and reports. In addition, the EPA issued its final incident situation report on November 29, 2012. The final construction documentation report was submitted to the WDNR on December 21, 2012.

In March 2012, the WDNR issued a Notice of Violation (NOV) along with its investigative findings. The NOV involved the north surface water detention basin and a related permit condition. A June 2012 letter from the WDNR rescinded the March 2012 NOV, but alleged non-compliance with certain environmental regulations. In late July 2012, the WDNR referred the matter to the Wisconsin Department of Justice (DOJ) for alleged violations of storm water and solid waste statutes and rules. We anticipate the DOJ will seek fines or penalties from us as a result of this incident.

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

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 Paris Generating Station (PSGS).

Solvay Coke and Gas Site:  We have been identified as a potentially responsible party at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company owned a parcel of property that is within the property boundaries of the site. In 2007, we and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. In-field investigation activities have commenced. Under the Administrative Settlement Agreement, we do not admit to any liability for the site, waive any liability defenses, or commit to perform future site remedial activities. Our share of the costs to perform the required work and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported in Note P --15, Commitments and Contingencies, in the Notes to Consolidated Financial Statements in Item 8.

Edgewater Generating Unit 5:In December 2009, the EPA issued a NOV concerning several coal-fired power plants owned and operated by WPL, including Edgewater Generating Unit 5, of which we owned 25%. Due to our ownership interest at the time, we were named in the NOV. In March 2011, we sold our interest to WPL. Although we sold our interest, we retained our share of liability, if any, related to the NOV. The NOV alleges that certain maintenance projects at WPL's units, including Edgewater 5, were undertaken without obtaining air permits required by the CAA. We, along with WPLNote 19, Regulatory Environment, for more information on material legal proceedings and the co-owners of the other plants identified in the NOV are discussing resolution of this NOV with the EPA. At this time, we cannot predict the outcome of this matter.


33Wisconsin Electric Power Company
ITEM 3. LEGAL PROCEEDINGS - (Cont'd)2012 Form 10-K

In September 2010, the Sierra Club filed a complaint against WPL generally alleging air permitting and opacity violations at the Edgewater Generating Station. We are not a named party to this litigation. WPL, the other co-owner of the Edgewater Generating Station, and us as a former co-owner, are discussing resolution of this matter with the Sierra Club. At this time, we cannot predict the outcome of this matter.

See Environmental Compliance in Item 1 and Environmental Matters, Manufactured Gas Plant Sites, Coal Combustion Product Landfill Sites and EPA - Consent Decree in Note P -- 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 wasteus and coal combustion product landfills, manufactured gas plant sites and air quality.


UTILITY RATE MATTERS

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

OTHER MATTERS

Used Nuclear Fuel Storage and Removal:See Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 for information concerning the United States Department of Energy's (DOE) breach of contract with us that required the DOE to begin permanently removing used nuclear fuel from Point Beach by January 31, 1998.

Cash Balance Pension Plan:   See Note P -- Commitments and Contingencies in the Notes to Consolidated Financial Statements for information regarding a lawsuit filed against the Wisconsin Energy Corporation Retirement Account Plan (Plan).

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
ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

2015 Form 10-K3426Wisconsin Electric Power Company
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2012 Form 10-K


EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, at December 31, 2012 and positions of our executive officers at December 31, 2015 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 theour 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 62.65.
WisconsinWEC Energy --Group — Director since 2003. Chairman of the Board and Chief Executive Officer since May 2004. President sincefrom April 2003.2003 to July 2013.
Wisconsin Electric --— Director since 2003. 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 sincefrom August 2003.2003 to June 2015.
Director of Joy Global, Inc. since 2006 and Badger Meter, Inc.
Director of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas since 2003.

Stephen P. Dickson.   Age 52.
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 1998.2010.

J. Kevin Fletcher.   Age 54.57.
Wisconsin Electric --— Director and Executive Vice President - Customer Service and Operations since June 2015. Senior Vice President since- Customer Operations from October 2011.
Wisconsin Gas -- Senior Vice President since October 2011.2011 to June 2015.
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 46.49.
WisconsinWEC Energy --Group — Executive Vice President - External Affairs since June 2015. Senior Vice President since- External Affairs from April 2011.2011 to June 2015.
Wisconsin Electric --— Executive Vice President - External Affairs since June 2015. Senior Vice President since- External Affairs from April 2011.2011 to June 2015.
Wisconsin Gas -- Senior Vice President since April 2011.
American Transmission Co. --ATC — Vice President and General Counsel from 2009 to April 2011.
NextEra
William J. Guc.   Age 46.
WEC Energy Resources --Group — Controller since October 2015. Vice President since June 2015.
Wisconsin Electric — Vice President and Controller since October 2015.
Integrys Energy Group — Vice President and Treasurer from 2007December 2010 to 2009.June 2015.

J. Patrick Keyes.   Age 47.50.
WisconsinWEC Energy --Group — Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to FebruaryJanuary 2013. Vice President from April 2011 to August 2012.
Wisconsin Electric --— Director since June 2015. 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 FebruaryJanuary 2013. Vice President from April 2011 to August 2012.
Accenture --— Senior Executive from September 20002001 to March 2011.

Frederick D. Kuester.   Scott J. Lauber.Age 62.50.
WEC Energy Group — Vice President and Treasurer since February 2013. Assistant Treasurer from March 2011 to January 2013.
Wisconsin Electric — Vice President and Treasurer since February 2013. Assistant Treasurer from March 2011 to January 2013.

Allen L. Leverett.   Age 49.
WEC Energy --Group — President since August 2013. Executive Vice President from May 2004 to January 4,July 2013. Chief Financial Officer from March 2011 to August 2012.
Wisconsin Electric -- Executive Vice President from May 2004 to January 4, 2013. Chief Operating Officer from October 2003 until February 2011. Chief Financial Officer from March 2011 to August 2012.
Wisconsin Gas -- Executive Vice President from May 2004 to January 4, 2013. Chief Financial Officer from March 2011 to August 2012.

Mr. Kuester retired effective January 4, 2013.




35Wisconsin Electric Power Company
EXECUTIVE OFFICERS OF THE REGISTRANT - (Cont'd)2012 Form 10-K

Mirant Corporation, of which Mr. Kuester was Senior Vice President - International from 2001 to October 2003 and Chief Executive Officer of Mirant Asia-Pacific Limited from 1999 to October 2003, and certain of its subsidiaries voluntarily filed for bankruptcy in July 2003. Other than certain Canadian subsidiaries, none of Mirant's international subsidiaries filed for bankruptcy.


Allen L. Leverett.   Age 46.
Wisconsin Energy -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 to February 2011.
Wisconsin Electric --— Director and President since June 2015. Executive Vice President sincefrom May 2004. Chief Financial Officer from July 20032004 to February 2011.
Wisconsin Gas -- Executive Vice President since May 2004.June 2015. Chief Financial Officer from July 2003 to February 2011.

Susan H. Martin.   Age 60.63.
WisconsinWEC Energy --Group — Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.
Wisconsin Electric -- Executive Vice President and General Counsel— Director since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.
Wisconsin Gas --June 2015. 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.


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Kristine A. Rappé.Joan M. Shafer.   Age 56.62.
Wisconsin Energy --Electric — Executive Vice President - Human Resources and Organizational Effectiveness since June 2015. Senior Vice President and Chief Administrative Officer since May 2004.
Wisconsin Electric -- Senior- Customer Services from January 2012 to June 2015. Vice President and Chief Administrative Officer since May 2004.
Wisconsin Gas -- Senior Vice President and Chief Administrative Officer since May 2004.- Customer Services from January 2004 to January 2012.

Ms. Rappé is concluding her employmentOn January 27, 2016, Mr. Klappa notified WEC Energy Group's Board of Directors (Board) of his decision to retire as Chief Executive Officer (CEO) of WEC Energy Group effective February 28, 2013.May 1, 2016, after which time he will serve as Non-Executive Chairman of the Board. On the same day, the Board elected Mr. Leverett to the Board and appointed him as CEO of WEC Energy Group effective upon Mr. Klappa's retirement.

Certain executive officers also hold offices in Wisconsin Energy's non-utilityofficer and/or director positions at other significant subsidiaries and our non-utility subsidiary.

of WEC Energy Group.


2015 Form 10-K3628Wisconsin Electric Power Company
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2012 Form 10-K

PART II


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


DIVIDENDSDividends

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

Quarter 2012 2011    
 (Millions of Dollars)
    
(in millions) 2015 2014
First $44.9
 $44.9
 $60.0
 $110.0
Second 44.9
 44.9
 60.0
 110.0
Third 44.9
 44.9
 60.0
 110.0
Fourth 44.9
 104.9
 60.0
 60.0
Total $179.6
 $239.6
 $240.0
 $390.0

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

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WisconsinWEC Energy Group in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. For additionalWEC Energy Group. See Note 9, Common Equity, for more information regarding restrictions on our ability to pay dividends, see Note H -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.

dividends.


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2012 Form 10-K

ITEM 6.SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA

WISCONSIN ELECTRIC POWER COMPANY
COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS
WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA
           
Financial 2012 2011 2010 2009 2008
Year Ended December 31          
Earnings available for
     common stockholder (Millions)
 $366.1
 $338.4
 $314.2
 $287.4
 $280.1
           
Operating Revenues (Millions)          
Electric $3,193.9
 $3,211.3
 $2,936.3
 $2,685.0
 $2,660.6
Gas 385.1
 477.3
 481.6
 564.2
 709.2
Steam 34.3
 39.0
 38.8
 39.1
 40.3
Total operating revenues $3,613.3
 $3,727.6
 $3,456.7
 $3,288.3
 $3,410.1
           
At December 31 (Millions)          
Total assets $12,022.6
 $11,661.3
 $10,170.7
 $8,871.2
 $8,775.4
Long-term debt and capital lease
     obligations (including current maturities)
 $5,276.8
 $5,022.0
 $4,053.5
��$3,092.8
 $2,886.4
           


CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
    
  (Millions of Dollars) (a) 
  March June 
Three Months Ended 2012 2011 2012 2011 
Total operating revenues $946.6
 $1,006.2
 $840.6
 $853.3
 
Operating income $172.3
 $155.3
 $132.3
 $81.2
 
Earnings available for common
     stockholder
 $115.6
 $107.2
 $83.0
 $57.8
 
          
  September December 
Three Months Ended 2012 2011 2012 2011 
Total operating revenues $951.9
 $958.3
 $874.2
 $909.8
 
Operating income $193.3
 $143.1
 $85.4
 $94.0
 
Earnings available for common
     stockholder
 $122.2
 $100.8
 $45.3
 $72.6
 
As of or for Year Ended December 31          
(in millions) 2015 2014 2013 2012 2011
Operating revenues $3,854.1
 $4,059.4
 $3,800.2
 $3,613.3
 $3,727.6
Net income attributed to common shareholder 375.7
 376.7
 360.0
 366.1
 338.4
Total assets (1) (2)
 13,139.6
 12,597.2
 12,207.2
 12,016.2
 11,659.3
Long-term debt and capital lease obligations (excluding current portion) (1)
 5,351.3
 4,875.2
 4,876.7
 4,917.5
 4,982.1

(a)
(1)
Quarterly resultsIn the fourth quarter of operations are not directly comparable because2015, we early implemented ASU 2015-03, Simplifying the Presentation of seasonalDebt Issuance Costs. As a result, debt issuance costs previously reported as other long-term assets were reclassified to offset long-term debt for all periods presented. Amounts reclassified were $2.8 million in 2014, $2.6 million in 2013, $2.3 million in 2012, and other factors. See Management's Discussion$2.0 million in 2011.

(2)
In the fourth quarter of 2015, we early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes. As a result, current deferred income taxes previously reported as a separate component of current assets were reclassified to offset long-term deferred income tax liabilities. Amounts reclassified were $46.7 million in 2014, $75.8 million in 2013, and Analysis of Financial Condition and Results of Operations.$4.1 million in 2012. No reclassification was needed for 2011.


2015 Form 10-K3830Wisconsin Electric Power Company
Table of Contents
2012 Form 10-K

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


CORPORATE DEVELOPMENTS

INTRODUCTIONIntroduction

Wisconsin Electric Power Company,We are a wholly owned subsidiary of WisconsinWEC Energy isGroup, and are primarily engaged primarily in the business of generating and distributing electricity in Wisconsin and the Upper Peninsula of Michigan, and distributing natural gas in Wisconsin. Unless qualified by their context when used in this document, the terms Wisconsin Electric, the Company, our, us or we refer to Wisconsin Electric Power Company and its subsidiary, Bostco.

Wisconsin Energy is also the parent company of Wisconsin Gas, a natural gas distribution utility, which serves customers throughout Wisconsin; and We Power, an unregulated company that was formed in 2001 to design, construct, own and lease to us the new generating capacity included in Wisconsin Energy's PTF strategy, which is described further in this report. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies." We conduct our business primarily in three reportable segments, an electric utility segment, a natural gas utility segment, and a steam utility segment. See Note 21, Segment Information, for more information on our reportable business segments.

Corporate Strategy

CORPORATE STRATEGYOur goal is to create long-term value for WEC Energy Group's stockholders and our customers by focusing on the following:

Business OpportunitiesReliability

We have two primary investment opportunitiesmade significant reliability related investments in recent years, and earnings streams:plan to continue making significant capital investments to strengthen and modernize the reliability of our regulated utility businessgeneration and our investment in ATC.distribution network.

Our regulatedinvestment in reliability related projects has been very successful. In October 2015, We Energies was named the most reliable utility business primarily consistsin the Midwest by PA Consulting Group for the fifth year in a row. We Energies received the ReliabilityOneTM Award, an annual award that recognizes utilities that excel in delivering reliable electric service.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of electric generation assetsour company. We have provided some examples from our generating fleet.

VAPP is a co-generation plant in Milwaukee that was constructed in 1968. The plant originally utilized coal to produce electricity and steam; however, the electric andplant's fuel source was converted to natural gas distribution assets that serve our electric and gas customers. During 2012, our regulated utility earned $583.3 million of operating income. Over the next three years, we expect to invest approximately $1.5 billionwith construction completed in this business to construct renewable generation, to convertNovember 2015. Changing the fuel source for VAPP from coalis expected to natural gas, to updatereduce operating costs and enhance environmental performance without decreasing the electric and gas distribution infrastructure, and for other utility projects.plant’s capacity.

We have a $332.6 million investment in ATC, which represents a 23.0% ownership interest. Our 2012 pre-tax earningsreceived approval from ATC totaled $57.6 million and we received $46.1 million in dividends from ATC. Over the next three years, we expectPSCW to make capital contributionschanges at the Oak Creek Expansion units to enable them to burn coal from the Powder River Basin (PRB) in the Western United States. The coal plant was originally designed to burn coal mined from the Eastern United States, but the price of approximately $38 millionthat coal increased relative to the PRB coal in ATC asrecent years. This project is expected to create flexibility and enable the plant to operate at lower costs, placing it continuesin a better position to investbe called upon in transmission projects. During the same period, we expect to invest $41 millionMISO Energy Markets, resulting in ATC through undistributed earnings.lower fuel costs for our customers.

Financial Discipline

A strong adherence to financial discipline is essential to earning our authorized ROE and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment that are no longer performing as intended, or have an unacceptable risk profile.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by embracing constructive change, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

2015 Form 10-K31Wisconsin Electric Power Company
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RESULTS OF OPERATIONS

EARNINGSConsolidated Earnings

2012 vs. 2011:   Earnings increasedThe following table compares our consolidated results:
  Year Ended December 31
(in millions) 2015 2014 2013
Electric utility segment $582.7
 $565.6
 $533.2
Natural gas utility segment 60.6
 77.2
 69.8
Steam utility segment 5.6
 7.6
 2.9
Total operating income 648.9
 650.4
 605.9
Equity in earnings of transmission affiliate 47.8
 57.9
 60.2
Other income, net 11.2
 8.7
 17.4
Interest expense 119.0
 116.5
 121.4
Income before income taxes 588.9
 600.5
 562.1
Income tax expense 212.0
 222.6
 200.9
Preferred stock dividend requirements 1.2
 1.2
 1.2
Net income attributed to common shareholder $375.7
 $376.7
 $360.0

Electric Utility Segment Contribution to $366.1 millionOperating Income

Electric utility margins are defined as electric revenues less fuel and purchased power costs. We believe that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric revenues since the majority of prudently incurred fuel and purchased power costs are passed through to customers in 2012 comparedcurrent rates under enacted fuel rules.
  Year Ended December 31
(in millions) 2015 2014 2013
Electric revenues $3,413.4
 $3,401.1
 $3,308.7
Fuel and purchased power 1,141.4
 1,214.0
 1,144.5
Total electric margins 2,272.0
 2,187.1
 2,164.2
       
Other operation and maintenance 1,309.1
 1,268.9
 1,323.8
Depreciation and amortization 270.4
 244.1
 201.5
Property and revenue taxes 109.8
 108.5
 105.7
Operating income $582.7
 $565.6
 $533.2

The following tables provide information on delivered volumes by customer class and weather statistics:
  Year Ended December 31
  
MWh (in thousands)
Electric Sales Volumes 2015 2014 2013
Customer class      
Residential 7,789.3
 7,946.3
 8,141.9
Small commercial and industrial 8,797.0
 8,805.1
 8,860.4
Large commercial and industrial 9,085.7
 7,393.3
 8,673.4
Other 147.7
 148.7
 152.3
Total retail 25,819.7
 24,293.4
 25,828.0
Wholesale 1,234.0
 1,852.8
 1,953.5
Resale 8,577.6
 6,497.9
 4,382.7
Total sales in MWh 35,631.3
 32,644.1
 32,164.2
Electric customer choice* 445.2
 2,440.0
 813.0

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

2015 Form 10-K32Wisconsin Electric Power Company
Table of Contents

  Year Ended December 31
  Degree Days
Weather * 2015 2014 2013
Heating (6,659 normal) 6,468
 7,616
 7,233
Cooling (712 normal) 622
 464
 688

*Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

2015 Compared with $338.4 million in 2011. 2014

Operating Income

Operating income at the electric utility segment increased $109.7$17.1 million between the comparative periods.and was driven by an $84.9 million increase in electric margins. The increase in electric margins resulted from:

A $38.4 million increase as a result of the PSCW rate order, effective January 1, 2015. See Note 19, Regulatory Environment, for more information.

A $35.0 million increase driven by the escrow accounting treatment of the SSR revenues in the PSCW rate order, effective January 1, 2015. See Note 19, Regulatory Environment, for more information.

A $24.2 million increase due to the return of the iron ore mines as customers in February 2015. The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. Effective February 1, 2015, the owner of the two mines returned them as retail customers. In 2015, we deferred, and expect to continue to defer, the margin from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice. See Note 20, Michigan Settlement, for more information. A large portion of this increase in margins was offset by higher transmission expense included in other operation and maintenance expense.

A $10.4 million increase in positive collections of fuel and purchased power costs as compared with costs approved in rates in 2015, as compared with 2014. Under the fuel rule, we defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates, and the remaining variance impacts margins.

A $6.2 million increase primarily due to lower fly ash removal costs in 2015. These costs are not included in the fuel rule recovery mechanism.

A partially offsetting $22.3 million decrease in electric margins related to sales volume variances in 2015. This decrease was driven by lower margins from residential customers in 2015, primarily due to lower weather-normalized use per customer and warmer weather during the heating season.

A partially offsetting $10.8 million decrease in wholesale margins driven by a reduction in sales volumes in 2015. Certain wholesale customers have provisions in their contracts which allow them to reduce the amount of energy we provide to them.

These increases in operating income was primarily caused by decreasedwere partially offset by:

A $40.2 million increase in other operation and maintenance expense, and decreased fuel and purchased power expenses.driven by:

2011 vs. 2010:   Earnings increased to $338.4 million in 2011 compared with $314.2 million in 2010. Operating income decreased $15.6 million between the comparative periods. The decrease in operating income was primarily caused by increased other operation and maintenance expense and unfavorable weather during 2011 as compared to 2010, partially offset by wholesale electric pricing increases and electric sales growth.
◦A $48.6 million increase from higher PTF lease expense and associated operating and maintenance expenses as approved in our PSCW rate order, effective January 1, 2015.

◦A $16.0 million increase in transmission expense from MISO and ATC related to the iron ore mines returning as customers in February 2015.

◦These increases in other operation and maintenance expenses were partially offset by:


2015 Form 10-K3933Wisconsin Electric Power Company
Table of Contents

ITEM 7.▪MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-KA $7.4 million decrease in electric distribution costs and amortization of design software, partially offset by higher electric maintenance costs.

The following table summarizes our consolidated earnings during 2012, 2011 and 2010:

  2012 2011 2010
  (Millions of Dollars)
Utility Gross Margin      
Electric (See below) $2,103.6
 $2,052.1
 $1,844.8
Gas (See below) 157.4
 171.1
 165.6
Steam 20.8
 23.7
 25.6
Total Gross Margin 2,281.8
 2,246.9
 2,036.0
Other Operating Expenses      
Other operation and maintenance 1,327.8
 1,447.6
 1,432.5
Depreciation and amortization 257.6
 220.3
 216.2
Property and revenue taxes 113.1
 105.4
 96.5
Amortization of gain —
 —
 (198.4)
Operating Income 583.3
 473.6
 489.2
Equity in Earnings of Transmission Affiliate 57.6
 54.9
 52.7
Other Income and Deductions, net 32.3
 62.1
 39.8
Interest Expense, net 113.2
 94.2
 101.5
Income Before Income Taxes 560.0
 496.4
 480.2
Income Tax Expense 192.7
 156.8
 164.8
Preferred Stock Dividend Requirement 1.2
 1.2
 1.2
Earnings Available for Common Stockholder $366.1
 $338.4
 $314.2



▪40Wisconsin Electric Power CompanyA $5.8 million decrease in employee benefits in 2015 driven by lower performance units share-based compensation, deferred compensation, and medical costs.

ITEM 7.▪MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-KOther decreases in other operation and maintenance expenses that were not individually significant.

Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2012 with similar information for 2011A $26.3 million increase in other depreciation and 2010, including a summary of electric operating revenues and electric sales by customer class:

  Electric Revenues and Gross Margin MWh Sales
Electric Utility Operations 2012 2011 2010 2012 2011 2010
  (Millions of Dollars) (Thousands)
Customer Class            
Residential $1,163.9
 $1,159.2
 $1,114.3
 8,317.7
 8,278.5
 8,426.3
Small Commercial/Industrial 1,013.6
 1,006.9
 922.2
 8,860.0
 8,795.8
 8,823.3
Large Commercial/Industrial 744.3
 763.7
 677.1
 9,710.7
 9,992.2
 9,961.5
Other - Retail 22.8
 22.9
 21.9
 154.8
 153.6
 155.3
Total Retail 2,944.6
 2,952.7
 2,735.5
 27,043.2
 27,220.1
 27,366.4
Wholesale - Other 144.4
 154.0
 134.6
 1,566.6
 2,024.8
 2,004.6
Resale - Utilities 53.4
 69.5
 40.4
 1,642.4
 2,065.7
 1,103.8
Other Operating Revenues 51.5
 35.1
 25.8
 —
 —
 —
Total 3,193.9
 3,211.3
 2,936.3
 30,252.2
 31,310.6
 30,474.8
             
Fuel and Purchased Power            
Fuel 541.6
 644.4
 570.5
      
Purchased Power 548.7
 514.8
 521.0
      
Total Fuel and Purchased Power 1,090.3
 1,159.2
 1,091.5
      
Total Electric Gross Margin $2,103.6
 $2,052.1
 $1,844.8
      
             
Weather -- Degree Days (a)            
Heating (6,662 Normal)       5,704
 6,633
 6,183
Cooling (696 Normal)       1,041
 793
 944
amortization expense, driven by:

(a)◦As measured at Mitchell International AirportAn overall increase in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.utility plant in service in 2015. During 2015, we completed the conversion of the fuel source for VAPP from coal to natural gas.


Electric Utility Revenues and Sales

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 the prior year 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 a settlement with the DOE. For additional information on the DOE settlement, see Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations.
A planned outage at an iron ore mine of our largest customer 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 an iron ore mine of our largest customer 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

41Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-K

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.

2011 vs. 2010:   Our electric utility operating revenues increased by $275.0 million, or 9.4%, when compared to 2010. The most significant factors that caused a change in revenues were:

2011 increase of approximately $198.4 million, reflecting the reduction of Point Beach bill credits to retail customers. For information on the bill credits, see Amortization of Gain below.
Net pricing increases totaling $48.8 million, which includes rates related to our 2010 fuel recovery request that became effective March 25, 2010, and our request to review 2011 fuel costs that became effective April 29, 2011. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.
Unfavorable weather as compared to 2010 that decreased electric revenues by an estimated $40.5 million.
A $20.4 million increase in revenue from energy sold into the MISO Energy Markets, which was driven by increased MWh generation from the Oak Creek expansion units.
Net economic growth that increased electric revenues by an estimated $16.2 million as compared to 2010.
Higher MWh sales to our wholesale customers, which increased revenue by an estimated $10.4 million as compared to 2010.

As measured by cooling degree days, 2011 was 11.8% warmer than normal, but 16.0% cooler than 2010. The 1.8% decrease in residential sales volumes in 2011 is primarily attributable to weather. The estimated 1.8% impact of cooler summer weather on our small commercial/industrial sales volumes was almost entirely offset by an estimated 1.5% increase in sales due to modest economic growth. Increased sales to our largest customers, two iron ore mines, accounted for the increase in sales to our large commercial/industrial customers. If these sales are excluded, sales to our large commercial/industrial customers decreased by approximately 1.2% for 2011 as compared to 2010 primarily because of previously announced plant closings.


Electric Fuel and Purchased Power Expenses

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.

2011 vs. 2010:   Our electric fuel and purchased power costs increased by $67.7 million, or approximately 6.2%, when compared to 2010. This increase was primarily caused by a 2.7% increase in total MWh sales as well as increased coal and related transportation costs, partially offset by 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 2012, 2011 and 2010. Operating revenues and cost of gas sold has declined over the last three years due to the decline in the commodity cost of natural gas during this three year period.

Gas Utility Operations 2012 2011 2010
  (Millions of Dollars)
       
Operating Revenues $385.1
 $477.3
 $481.6
Cost of Gas Sold 227.7
 306.2
 316.0
Gross Margin $157.4
 $171.1
 $165.6


42Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-K

We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under our GCRM. The following table compares our gas utility gross margin and therm deliveries by customer class during 2012, 2011 and 2010:

  Gross Margin Therm Deliveries
Gas Utility Operations 2012 2011 2010 2012 2011 2010
  (Millions of Dollars) (Millions)
Customer Class            
Residential $106.1
 $114.7
 $111.2
 294.3
 339.4
 321.8
Commercial/Industrial 33.0
 38.1
 35.8
 165.3
 198.7
 184.5
Interruptible 0.5
 0.5
 0.6
 5.0
 5.3
 5.5
Total Retail 139.6
 153.3
 147.6
 464.6
 543.4
 511.8
Transported Gas 16.5
 16.3
 15.5
 344.5
 294.4
 300.8
Other 1.3
 1.5
 2.5
 —
 —
 —
Total $157.4
 $171.1
 $165.6
 809.1
 837.8
 812.6
             
Weather -- Degree Days (a)            
Heating (6,662 Normal)       5,704
 6,633
 6,183

(a)◦As measured at Mitchell International AirportA new depreciation study approved by the PSCW, effective January 1, 2015.

◦A $7.7 million reduction in Milwaukee,income received in 2015 from a Treasury Grant associated with the completion of our biomass plant in 2013. The lower grant income corresponds to lower bill credits provided to our retail electric customers in Wisconsin. Normal degree days are based upon a 20-year moving average.

2012 vs. 2011:   Our total retail gas margin decreased by $13.72014 Compared with 2013

Operating Income

Operating income at the electric utility segment increased $32.4 million,, or approximately 8.9%, when compared to 2011 primarily because of a decrease driven by:

A $120.9 million increase in sales volumesfor resale in 2014 due to higher sales into the MISO Energy Markets as a result of warmer winter weather. As measured by heating degree days, 2012 was 14.0% warmer than 2011Michigan's alternative electric supplier program and 14.4% warmer than normal.increased availability of our generating units. The margins on these sales are used to reduce fuel costs for our retail customers.

Transported gas volumes increasedA $59.4 million increase in other operating revenues in 2014, primarily driven by 17.0% when compared to 2011. Virtually allthe recognition of the volume increase$56.4 million related to gas used in electric generation, which has a small impact on margin.revenues under the SSR agreement with MISO. See Note 20, Michigan Settlement, for more information.

2011 vs. 2010:   Our gas margin increased by $5.5A $54.9 million or approximately 3.3%, when compared to 2010 primarily because of an increasedecrease in sales volumes as a result of colder winter weather in 2011 as compared to 2010. As measured by heating degree days, 2011 was 7.3% colder than 2010 and 0.3% colder than normal.


Other Operation and Maintenance Expense

2012 vs. 2011:   Our other operation and maintenance expense decreased by $119.8 million, or approximately 8.3%, when compared to 2011.in 2014. This decrease iswas primarily duedriven by lower benefit costs related to the one year suspension of $148 million of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case. For additional information on the 2012 rate case, see Factors Affecting Results, Liquiditypension, postretirement, and Capital Resources -- Rates and Regulatory Matters.

medical costs. Our operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages, and amortization of regulatory assets. We expect our 2013 other operation and maintenance expense to stay fairly flat because we anticipate that the 2013 Wisconsin Rate Case reinstatement of amortization on certain regulatory assets will be offset by an extension of the recovery period for certain regulatory assets and a significant reduction of escrowed bad debt expense.

2011 vs. 2010:   Our other operation and maintenance expense increased by $15.1A $38.3 million or approximately 1.1%, when compared to 2010. Higher maintenance costs at one of our natural gas peaking plants, increased spending on forestry work for our electric distribution system and increased costs associated with the amortization of deferred PTF costsincrease in Wisconsin net retail pricing in 2014, primarily related to wholesale and Michigan customers were the primary drivers of the increase.our PSCW rate order, effective January 1, 2013.


Depreciation and Amortization ExpenseThese increases in operating income were partially offset by:

2012 vs. 2011:   DepreciationA $78.4 million decrease in large commercial and Amortization expense increased by $37.3industrial sales in 2014 due to the two iron ore mines switching to an alternative electric supplier in September 2013.

A $69.5 million, or approximately 16.9%, when compared to 2011. increase in electric fuel and purchased power costs in 2014. This increase was primarily becausedriven by a 1.5% increase in total MWh sales and higher generating costs due to an increase in natural gas prices.

A $42.6 million increase in depreciation and amortization expense in 2014. The increase was partially driven by lower income received from a Treasury Grant in 2014. During 2014, we recognized $17.4 million of income related to a Treasury Grant associated with the completion of the biomass plant, compared to $48.0 million in 2013. The lower grant income corresponds to the lower bill credits provided to our retail electric customers in Wisconsin in 2014. In addition, an overall increase in utility plant in service. The Glacier

43Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-K

Hills Wind Parkservice as a result of the biomass plant that went into service in December 2011. In addition,November 2013 contributed to the emission control equipment for units 5 and 6 of the Oak Creek AQCS project went into serviceincrease in March 2012, and for units 7 and 8 in September 2012. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

We expect depreciation and amortization expense to increaseexpense.

A $45.8 million decrease in 2013 primarily as a result of an increase in utility plant in serviceelectric revenues related to the Oak Creek AQCS project, which will have beenunseasonably cool summer weather in service a full year.

2011 vs. 2010:   Depreciation2014. As measured by cooling degree days, 2014 was 36.6% cooler than normal and Amortization expense increased by $4.1 million, or approximately 1.9%, when compared32.6% cooler than 2013 due to 2010. This increase was primarily because of an overall increase in utility plant in service.


Amortization of Gain

In connection with the September 2007 sale of Point Beach, we reached an agreement with our regulators to allow for the net gain on the sale to be used for the benefit of our customers.mild second and third quarters. The majorityunfavorable impact of the benefits were returned to customers incool summer weather was partially offset by the form of bill credits. The net gain was originally recorded as a regulatory liability, and it was amortized to the income statement as we issued bill credits to customers. When the bill credits were issued to customers, we transferred cash from the restricted accounts to the unrestricted accounts, adjusted for taxes. All bill credits associated with the sale of Point Beach were applied to customers as of December 31, 2010, and as a result, the Amortization of Gain was zero during 2012 and 2011 as compared to $198.4 million during 2010.


Other Income and Deductions, net

Other Income and Deductions, net 2012 2011 2010
  (Millions of Dollars)
       
AFUDC - Equity $34.9
 $59.2
 $32.4
Gain on Property Sales 1.3
 2.4
 4.5
Other, net (3.9) 0.5
 2.9
Total Other Income and Deductions, net $32.3
 $62.1
 $39.8

2012 vs. 2011:   Other income and deductions, net decreased by approximately $29.8 million, or 48.0%, when compared to 2011. This decrease primarily relates to 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.

During 2013, we expect to see a reduction in AFUDC - Equity as we expect to have fewer large construction projects.

2011 vs. 2010:   Other income and deductions, net increased by approximately $22.3 million, or 56.0%, when compared to 2010. This increase primarily relates to increased AFUDC - Equity related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park.


Interest Expense, net

Interest Expense, net 2012 2011 2010
  (Millions of Dollars)
       
Gross Interest Costs $127.7
 $118.9
 $115.0
Less: Capitalized Interest 14.5
 24.7
 13.5
Interest Expense, net $113.2
 $94.2
 $101.5
cold winter weather.


2015 Form 10-K4434Wisconsin Electric Power Company
Table of Contents

ITEM 7.◦MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-KResidential sales decreased 2.4%, primarily due to the weather.

2012 vs. 2011:   Our gross interest costs increased by $8.8 million, or 7.4%, during 2012, primarily because of higher average long-term debt balances compared to 2011, including $300 million of long-term debt issued in September 2011. Our capitalized interest decreased by $10.2 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. As a result, our net interest expense increased by $19.0 million, or 20.2%, as compared to 2011.

During 2013, we expect to see higher net interest expense because of a reduction in capitalized interest as a result of the Oak Creek AQCS project emission control equipment going into service in 2012, partially offset by the expected increase in capitalized interest associated with the biomass plant which is expected to go into service by the end of 2013.

2011 vs. 2010:   Our gross interest costs increased by $3.9 million, or 3.4%, during 2011, primarily because of higher average long-term debt balances compared to 2010. In September 2011, we issued $300 million of long-term debt and used the net proceeds to repay short-term debt and for other general corporate purposes. Our capitalized interest increased by $11.2 million primarily because of increased capital expenditures related to our Oak Creek AQCS project and the Glacier Hills Wind Park. As a result, our net interest expense decreased by $7.3 million, or 7.2%, as compared to 2010.

◦Sales to our large commercial and industrial customers decreased 14.8% primarily due to the loss of the two iron ore mines in Michigan. If the mines were excluded, sales to our large commercial and industrial customers would have decreased 1.1%.

Natural Gas Utility Segment Contribution to Operating Income Tax Expense

2012 vs. 2011:   Our effective tax rate was 34.4%Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in 2012 compared with 31.6%current rates. The average per-unit cost of natural gas sold decreased 32.4% in 2011. This increase2015 and increased 44.7% in our effective tax rate was primarily the result2014, neither of decreased AFUDC - Equity. For further information, see Note G -- Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2013 annual effective tax rate to be between 36% and 37%.which had an impact on margins.
  Year Ended December 31
(in millions) 2015 2014 2013
Natural gas revenues 399.7
 614.2
 451.9
Cost of natural gas sold 244.6
 432.6
 278.3
Total natural gas margins 155.1
 181.6
 173.6
       
Other operation and maintenance 59.2
 70.0
 75.0
Depreciation and amortization 29.1
 30.5
 25.5
Property and revenue taxes 6.2
 3.9
 3.3
Operating income $60.6
 $77.2
 $69.8

2011 vs. 2010:   Our effective income tax rate was 31.6% in 2011 compared with 34.3% in 2010. This reduction in our effective tax rate was primarily the result of increased AFUDC - Equity.


LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2012, 2011tables provide information on delivered volumes by customer class and 2010:weather statistics:
  Year Ended December 31
  
Therms (in millions)
Natural Gas Sales Volumes 2015 2014 2013
Customer class      
Residential 341.2
 399.3
 380.8
Commercial and industrial 194.5
 240.4
 215.7
Other 0.6
 0.7
 0.6
Total retail 536.3
 640.4
 597.1
Transport 342.8
 343.1
 327.6
Total sales in therms 879.1
 983.5
 924.7

  2012 2011 2010
  (Millions of Dollars)
Cash Provided by (Used in)      
Operating Activities $807.0
 $543.9
 $425.2
Investing Activities $(605.6) $(762.1) $(470.8)
Financing Activities $(180.0) $207.6
 $50.6
  Year Ended December 31
  Degree Days
Weather * 2015 2014 2013
Heating (6,659 normal) 6,468
 7,616
 7,233

*Normal heating degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

2015 Compared with 2014

Operating ActivitiesIncome

2012 vs. 2011:   Cash provided by operating activities was $807.0Operating income at the natural gas utility segment decreased $16.6 million, during 2012, which was an increase of $263.1 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 flow by $249.9 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. driven by:

2011 vs. 2010:   Cash provided by operating activities was $543.9A $26.5 million during 2011, which was an increase of $118.7 million over 2010. The largest increasesdecrease in cash provided by operating activities related to higher net income, higher deferred income tax benefits and the elimination of the amortization of the gain on the sale of Point Beach. Combined these items totaled $604.7 million during 2011 as compared to $186.6 million during 2010. The

natural gas margins in 2015 resulting from:

◦45Wisconsin Electric Power CompanyA $14.9 million decrease from sales volume variances largely related to warmer weather during the heating season as well as lower weather-normalized use per customer. As measured by heating degree days, 2015 was 15.1% warmer than 2014.
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-K

largest reduction in cash provided by operating activities related to our contributions to our qualified benefit plans. During 2011, we contributed $275.1 million to our qualified benefit plans. We made no contributions to our qualified plans during 2010.

Investing Activities

2012 vs. 2011:   Cash used in investing activities was $605.6 million during 2012, which was $156.5 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 $130.8 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 $3.3 million in 2012.

2011 vs. 2010:   Cash used in investing activities was $762.1 million during 2011, which was $291.3 million higher than 2010. This increase in cash used primarily reflects changes in restricted cash and increased capital expenditures. During 2011, our restricted cash increased by $37.2 million primarily because of the nuclear fuel settlement we received from the DOE. During 2010, our restricted cash decreased by $186.2 million due to the release of restricted cash related to the Point Beach bill credits. In addition, capital expenditures increased by approximately $89.3 million during 2011 as compared to 2010 primarily due to increased spending related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park in 2011 as compared to 2010.

Financing Activities

The following table summarizes our cash flows from financing activities:

  2012 2011 2010
  (Millions of Dollars)
       
Dividends to Wisconsin Energy $(179.6) $(239.6) $(179.6)
Capital Contribution from Wisconsin Energy —
 —
 100.0
Net Increase in Debt 0.1
 440.7
 117.9
Other (0.5) 6.5
 12.3
Cash (Used in) Provided by Financing $(180.0) $207.6
 $50.6

2012 vs. 2011:   Cash used in financing activities was $180.0 million during 2011 compared to $207.6 million provided by financing activities during 2011. This change is primarily due to changes in our debt levels. During 2012, we issued $250 million of long-term debt and used the net proceeds to repay short-term debt and for other general corporate purposes compared to $300 million of long-term debt issued in 2011. In addition, short-term debt decreased $249.9 million in 2012 compared to a $140.7 million increase in 2011. For additional information on the debt issuance, see Note I -- Long-Term Debt and Capital Lease Obligations in the Notes to Consolidated Financial Statements.

Dividends to Wisconsin Energy decreased by $60 million in 2012 compared to 2011 due to payment of a special dividend of $60 million to Wisconsin Energy in 2011 in anticipation of the 2012 Wisconsin rate case. The PSCW approved this dividend as part of our 2012 rate case order.

2011 vs. 2010:   Cash provided by financing activities was $207.6 million during 2011 compared to $50.6 million provided by financing activities during 2010. During 2011, we issued $300 million of long-term debt and used the net proceeds to repay short-term debt and for other general corporate purposes. Partially offsetting the increase in debt is the payment of a $60 million special dividend to Wisconsin Energy and not receiving a capital contribution from Wisconsin Energy in 2011 compared to a $100 million capital contribution in 2010.




2015 Form 10-K4635Wisconsin Electric Power Company
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A $10.7 million decrease in margins as a result of the impact of the PSCW rate order, effective January 1, 2015. See Note 19, Regulatory Environment, for more information.

These decreases in operating income were partially offset by $10.8 million of lower other operation and maintenance expense in 2015, primarily driven by lower amortizations related to energy conservation programs as approved in the PSCW rate order, effective January 1, 2015.

2014 Compared with 2013

Operating Income

Operating income at the natural gas utility segment increased $7.4 million, driven by:

An $8.0 million increase in natural gas margins, primarily due to colder winter weather in 2014. We estimate that colder winter weather increased natural gas margins by approximately $5.0 million. As measured by heating degree days, 2014 was 5.3% colder than 2013 and 15.4% colder than normal.

A $5.0 million decrease in other operation and maintenance expense, primarily driven by lower benefit costs related to pensions, postretirement, and medical costs. Our operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages, and amortization of regulatory assets.

These increases in operating income were partially offset by a $5.0 million increase in depreciation and amortization expense, primarily due to an overall increase in utility plant in service.

Steam Utility Segment Contribution to Operating Income

Steam utility margins are defined as steam revenues less fuel costs. We believe that steam utility margins provide a more meaningful basis for evaluating steam utility operations than steam revenues since the majority of prudently incurred fuel costs are passed through to customers in current rates under enacted fuel rules.

  Year Ended December 31
(in millions) 2015 2014 2013
Steam revenues $41.0
 $44.1
 $39.6
Fuel costs 13.0
 14.1
 13.6
Total steam margins 28.0
 30.0
 26.0
       
Other operation and maintenance 16.6
 17.5
 18.5
Depreciation and amortization 4.5
 3.7
 3.6
Property and revenue taxes 1.3
 1.2
 1.0
Operating income $5.6
 $7.6
 $2.9

  Year Ended December 31
(in millions) 2015 2014 2013
Pounds of steam sales 2,515
 2,865
 2,750

2015 Compared with 2014

Operating Income

There was no material change in operating income for steam utility segment operations in 2015.


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2014 Compared with 2013

Operating Income

There was no material change in operating income for steam utility segment operations in 2014.

Equity in Earnings of Transmission Affiliate
  Year Ended December 31
(in millions) 2015 2014 2013
Earnings from ATC $47.8
 $57.9
 $60.2

2015 Compared with 2014

Earnings from our ownership interest in ATC decreased $10.1 million when compared to 2014, driven by lower earnings recognized by ATC, as ATC further reduced earnings in 2015 related to an anticipated refund to customers resulting from a complaint filed with the FERC requesting a lower ROE for certain transmission owners. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – ATC Allowed ROE Complaint, for more information.

2014 Compared with 2013

Earnings from our ownership interest in ATC decreased $2.3 million when compared to 2013. ATC reduced its earnings in 2014, driven by a potential refund to customers related to a complaint filed with the FERC requesting lower ROE for certain transmission owners.

Consolidated Other Income, Net
  Year Ended December 31
(in millions) 2015 2014 2013
AFUDC – Equity $5.7
 $4.4
 $17.6
Gain on asset sales —
 4.3
 0.8
Other, net 5.5
 —
 (1.0)
Other income, net $11.2
 $8.7
 $17.4

2015 Compared with 2014

Other income, net increased by $2.5 million when compared to 2014. This increase was not significant.

2014 Compared with 2013

Other income, net decreased by $8.7 million when compared to 2013. This decrease primarily relates to lower AFUDC – Equity related to the biomass plant going into service in November 2013, partially offset by an increased gain on asset sales.

Consolidated Interest Expense
  Year Ended December 31
(in millions) 2015
2014
2013
Interest expense $119.0
 $116.5
 $121.4

2015 Compared with 2014

Interest expense increased by $2.5 million, or 2.1%, when compared to 2014. This increase was not significant.


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2014 Compared with 2013

Our interest expense decreased by $4.9 million, or 4.0%, as compared to 2013 primarily because of lower average interest rates on long-term debt.

Income Tax Expense
  Year Ended December 31
  2015
2014
2013
Effective tax rate 36.0% 37.1% 35.7%

2015 Compared with 2014

Our effective tax rate was 36.0% in 2015 compared with 37.1% in 2014. This decrease in our effective tax rate was primarily due to increased production activities deductions. See Note 13, Income Taxes, for more information. We expect our 2016 annual effective tax rate to be between 36.0% and 37.0%.

2014 Compared with 2013

Our effective tax rate was 37.1% in 2014 compared with 35.7% in 2013. This increase in our effective tax rate was due to reduced tax benefits associated with Treasury Grant income and decreased AFUDC – Equity.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during 2015, 2014, and 2013:
(in millions) 2015 2014 2013 Change in 2015 Over 2014 Change in 2014 Over 2013
Cash provided by (used in)          
Operating activities $674.4
 $862.8
 $862.6
 $(188.4) $0.2
Investing activities (520.2) (567.5) (560.1) 47.3
 (7.4)
Financing activities (151.1) (296.4) (311.5) 145.3
 15.1

Operating Activities

2015 Compared with 2014

Net cash provided by operating activities decreased $188.4 million in 2015, primarily driven by:

A $97.2 million increase in contributions to our pension and OPEB plans in 2015.

A $76.2 million decrease in cash in 2015 from the Treasury Grant received in 2014 associated with the completion of our biomass plant in November 2013.

A $37.7 million decrease in cash related to higher cash paid for income taxes, net of refunds, in 2015.

2014 Compared with 2013

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


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Investing Activities

2015 Compared with 2014

Net cash used in investing activities decreased $47.3 million in 2015, driven by a decrease in capital expenditures (discussed below), primarily at the electric utility segment, related to the conversion of the fuel source for VAPP from coal to natural gas. Most of the capital expenditures related to this project were incurred in 2014.

2014 Compared with 2013

Net cash used in investing activities increased $7.4 million in 2014, primarily due to a $22.9 million increase in capital expenditures (discussed below), primarily at the electric utility segment, related to the conversion of the fuel source for VAPP from coal to natural gas in 2014. Partially offsetting this increase was a decrease in customer advances for construction projects in 2014.

Capital Expenditures

Capital expenditures by business segment for the year ended December 31 were as follows:
Reportable Segment (in millions)
 2015 2014 2013 Change in 2015 Over 2014 Change in 2014 Over 2013
Electric utility $444.6
 $489.3
 $467.8
 $(44.7) $21.5
Natural gas utility 71.7
 69.3
 60.0
 2.4
 9.3
Steam utility 2.9
 3.2
 11.1
 (0.3) (7.9)
WEPCO consolidated $519.2
 $561.8
 $538.9
 $(42.6) $22.9

See Capital Expenditures and Significant Projects below for more information.

Financing Activities

2015 Compared with 2014

Net cash used in financing activities decreased $145.3 million in 2015, driven by:

A $250.0 million increase in the issuance of long-term debt in 2015.

A $150.0 million decrease in dividends paid on common stock in 2015. In 2014, we paid $150.0 million of special dividends to Wisconsin Energy Corporation to balance our capital structure.

A $50.0 million decrease in the retirement of long-term debt in 2015.

These increases in cash were partially offset by a $294.7 million net decrease in cash related to $162.8 million of net repayments of commercial paper in 2015, compared with $131.9 million of net borrowings in 2014.

2014 Compared with 2013

Net cash used in financing activities decreased $15.1 million in 2014, primarily due to a $63.5 million increase in short-term debt in 2014, partially offset by a $50.0 million increase in special dividends paid to legacy Wisconsin Energy Corporation to balance our capital structure in 2014.

Significant Financing Activities

For information on our short-term debt, see Note 11, Short-Term Debt and Lines of Credit.

For information on our long-term debt, see Note 12, Long-Term Debt and Capital Lease Obligations.


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CAPITAL RESOURCES AND REQUIREMENTSCapital Resources and Requirements

Working Capital Resources

As of December 31, 2012, our current liabilities exceeded our current assets by approximately $77.7 million. Included in our current liabilities is approximately $357.0 million of long-term debt and capital lease obligations due currently. We do not expect this to have any impact on our liquidity because we believe we have an adequate back-up line of credit in place for on-going operations. We also have access to the capital markets to finance our construction program and to refinance current maturities of long-term debt if necessary.

Liquidity

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

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

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

As of December 31, 2012, we had approximately $494.1 million of available, undrawn lines under our bank back-up credit facility. As of December 31, 2012, we had approximately $105.5 million of commercial paper outstanding that was supported by the available line of credit. During 2012, our maximum commercial paper outstanding was $382.0 million with a weighted-average interest rate of 0.26%. For additional information regarding our commercial paper balances during 2012, see Note J -- 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 suchSee Note 11, Short-Term Debt and Lines of Credit, for more information about our credit facility as of December 31, 2012:and other short-term credit agreements.

Total Facility Letters of Credit Credit Available 
Facility
Expiration
(Millions of Dollars)  
       
$500.0 $5.9
 $494.1
 December 2017

On December 12, 2012, we entered into an unsecured five-year $500 million bank back-up credit facility to replace a $500 million three-year credit facility with an expiration date of December 2013. This new facility will expire in December 2017 and has a renewal provision for two one-year extensions, subject to lender approval.


47Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-K

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

Capitalization Structure 2012 2011
  (Millions of Dollars)
         
Common Equity $3,366.4
 38.2% $3,177.1
 36.9%
Preferred Stock 30.4
 0.3% 30.4
 0.4%
Long-Term Debt (a) 2,516.7
 28.6% 2,267.6
 26.3%
Capital Lease Obligations (a) 2,760.1
 31.4% 2,754.4
 32.0%
Short-Term Debt (b) 128.9
 1.5% 378.8
 4.4%
Total $8,802.5
 100.0% $8,608.3
 100.0%
         
(a) Includes current maturities        
(b) Includes subsidiary note payable to Wisconsin Energy    
(in millions) 2015 2014
Common equity $3,564.0
 38.6% $3,412.8
 37.9%
Preferred stock 30.4
 0.3% 30.4
 0.3%
Long-term debt 2,658.8
 28.8% 2,412.7
 26.8%
Capital lease obligations (1)
 2,816.1
 30.5% 2,818.1
 31.3%
Short-term debt (2)
 163.6
 1.8% 329.2
 3.7%
Total $9,232.9
 100.0% $9,003.2
 100.0%

(1)
Includes current maturities.

(2)
Includes subsidiary note payable to WEC Energy Group.

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.our capitalization statements.

At December 31, 2015, we were in compliance with all covenants related to outstanding short-term and long-term debt. We are the obligor under two series of tax exempt pollution control refunding bondsexpect to be in outstanding principal amounts of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity supportcompliance with all such debt covenants for the bonds, which resulted in a mandatory tenderforeseeable future. See Note 11, Short-Term Debt and Lines of the bonds. We issued commercial paper to fund the purchase of the bonds. As of December 31, 2012, the repurchased bonds were still outstanding, but were reported as a reduction inCredit, for more information on our consolidated long-term debt because they are held by us. Depending on market conditionscredit facility and other factors, we may change the method used to determine the interest rateshort-term credit agreements. See Note 12, Long-Term Debt and Capital Lease Obligations, for more information on the bonds and have them remarketed to third parties.our long-term debt.

Bonus Depreciation Provisions

As a result of the enactment of tax legislation extending the bonus depreciation rules, we recognized increased federal tax depreciation through 2012 relating to assets placed into service including the Glacier Hills Wind Park and the Oak Creek AQCS project. As a result of this increased federal tax depreciation we did not make federal income tax payments for 2012 and do not anticipate making federal income tax payments for 2013. 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.
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, 2012, we estimate that the collateral or the termination payments required under these agreements totaled approximately $223.0 million. Generally, collateral may be provided by a guaranty, letter of credit or cash. We also have other commodity contracts that in the event of a credit rating downgrade could result in a reduction of our unsecured credit granted by counterparties.

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

In December 2012, Moody's affirmed our ratings (commercial paper, P-1; senior unsecured, A2) and our stable ratings outlook.

In June 2012, S&P affirmed our ratings (commercial paper, A-2; senior unsecured, A-) and revised our ratings outlook from stable to positive.

In June 2012, Fitch Ratings (Fitch) affirmed our ratings (commercial paper, F1; senior unsecured, A+) and our stable ratings outlook.

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ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-K


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 2013, 2014 and 2015 capital expenditures are $521.6 million, $461.0 million and $480.3 million, respectively. The majority of spending consists of upgrading our electric and gas distribution systems. Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such as air quality standards, renewable energy standards and electric reliability initiatives that impact us.Contractual Obligations

Investments in Outside Trusts:   We use outside trusts to fund our pension and certain other post-retirement obligations. These trusts had investments of approximately $1.3 billion as of December 31, 2012. These trusts hold investments that are subject to the volatility of the stock market and interest rates.

During 2012, we contributed $88.5 million to our qualified pension plans and $4.4 million to our qualified Other Post-Retirement Employee Benefit (OPEB) plans. During 2011, we contributed $234.1 million to our qualified pension plans and $41.0 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 M -- 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 commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For additional information, see Note F -- Variable Interest Entities in the Notes to Consolidated Financial Statements in this report.

Contractual Obligations/Commercial Commitments:   We have the following contractual obligations and other commercial commitments as of December 31, 2012:

2015:
  Payments Due by Period
Contractual Obligations (a) Total Less than 1 year 1-3 years 3-5 years More than 5 years
  (Millions of Dollars)
           
Long-Term Debt Obligations (b) $4,572.1
 $422.4
 $754.0
 $230.3
 $3,165.4
Capital Lease Obligations (c) 10,248.5
 408.8
 822.2
 845.1
 8,172.4
Operating Lease Obligations (d) 47.1
 6.5
 7.9
 6.8
 25.9
Purchase Obligations (e) 12,196.4
 782.0
 1,186.0
 933.7
 9,294.7
Other Long-Term Liabilities 861.0
 89.5
 174.8
 173.4
 423.3
Total Contractual Obligations $27,925.1
 $1,709.2
 $2,944.9
 $2,189.3
 $21,081.7
  
Payments Due by Period (1)
(in millions) Total Less than 1 year 1-3 years 3-5 years More than 5 years
Long-term debt obligations (2)
 $5,104.2
 $115.9
 $477.8
 $460.8
 $4,049.7
Capital lease obligations (3)
 9,422.5
 459.5
 858.2
 861.5
 7,243.3
Operating lease obligations (4)
 37.8
 4.9
 7.1
 2.7
 23.1
Energy and transportation purchase obligations (5)
 10,775.5
 713.4
 1,168.5
 1,000.0
 7,893.6
Purchase orders (6)
 103.5
 44.2
 31.7
 17.6
 10.0
Pension and OPEB funding obligations (7)
 20.5
 6.7
 13.8
 —
 —
Capital contributions to equity method investments 3.4
 3.4
 —
 —
 —
Total contractual obligations $25,467.4
 $1,348.0
 $2,557.1
 $2,342.6
 $19,219.7

(a)
(1)
The amounts included in the table are calculated using current market prices, forward curves, and other estimates.

(b)
(2)
Principal and interest payments on Long-Term Debtlong-term debt (excluding capital lease obligations).

(c)
(3)
Capital Lease Obligationslease obligations for power purchase commitments and the PTF leases.

(d)
(4)
Operating Lease Obligationslease obligations for power purchase commitments and rail car leases.

(e)
(5)
Purchase ObligationsEnergy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation and for construction,related to utility operations.

(6)
Purchase obligations related to normal business operations, information technology, and other services for utility operations. This includes the power purchase agreement for Point Beach.services.

(7)
49Wisconsin Electric Power CompanyObligations for pension and OPEB plans cannot reasonably be estimated beyond 2018.
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-K



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 --13, Income TaxesTaxes.

AROs in the Notes to Consolidated Financial Statementsamount of $58.7 million are not included in this report.the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years.

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

Capital Expenditures and Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:
(in millions)  
2016 $495.7
2017 532.3
2018 608.9
Total $1,636.9

The majority of spending consists of upgrading our electric and natural gas distribution systems.


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We expect to provide capital contributions to ATC (not included in the above table) of approximately $121 million from 2016 through 2018.

Common Stock Matters

For information related to our common stock matters, see Note 9, Common Equity.

Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $1.4 billion as of December 31, 2015. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $107.6 million, $10.4 million, and $17.6 million to our pension and OPEB plans in 2015, 2014, and 2013, respectively. 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 14, Employee Benefits.

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 letters of credit which primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. For additional information, see Note 18, Variable Interest Entities, and Note 11, Short-Term Debt and Lines of Credit.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES


MARKET RISKS AND OTHER SIGNIFICANT RISKSMarket 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:   Recovery

We account for our regulated operations in accordance with accounting guidance for regulated entities.under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory authorities. Our primary regulator is the PSCW. See Note 19, Regulatory Environment, for additional information regarding recent rate proceedings and orders.

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, our regulatory assets are recovered in a period between one to eightsix years. Regulatory assets associated with pension and OPEB expenses are amortized as a component of pension and OPEB expense. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2012,2015, our regulatory assets totaled $1,481.2$1,855.9 million and our regulatory liabilities totaled $601.8 million.$741.2 million.

Commodity Prices:   Costs
In the normal course of providing energy, we are subject to market fluctuations ofin the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural 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 utilizingthrough natural gas and electric hedging programs.

Wisconsin's retail electricEmbedded within our rates are amounts to recover fuel, cost adjustment procedure mitigates somenatural gas, and purchased power costs. We have recovery mechanisms in place that allow us to recover or refund all or a portion of our risk of electric fuel cost fluctuation. Effective January 1, 2011, the PSCW implemented new fuel rules which allow for a deferral ofchanges in prudently incurred fuel, natural gas, and purchased power 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. Forfrom rate case-approved amounts. See Item 1. Business – C. Regulation for more information regarding the fuel rules, see Rates and Regulatory Matters -- Wisconsin Fuel Rules.on these mechanisms.


Natural Gas Costs:   
2015 Form 10-K42Wisconsin Electric Power Company
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Higher natural gascommodity costs couldcan increase our working capital requirements, and result in higher gross receipts taxes, in the state of Wisconsin.and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher natural gascommodity 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 bySee Note 1(d), Revenues and Customer Receivables, for more information on our customers to reduce utility usage and/mechanism that allows for cost recovery or fuel substitution.refund of uncollectible expense.

Weather

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 our GCRM, our gas utility operation receives dollar for dollar recovery on the cost of natural gas.

50Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2012 Form 10-K

However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins. For information concerning our natural gas utility's GCRM, see Rates and Regulatory Matters.

Weather:Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages.normal temperatures. Our electric revenues and sales are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas revenues and sales are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2012, 20112015, 2014 and 2010,2013, as measured by degree days, may be found above in Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

Interest Rates

Interest Rate:We have variousare exposed to interest rate risk resulting from our short-term borrowing arrangementsborrowings and projected near-term debt financing needs. We manage exposure to provide working capital and general corporate funds. We also haveinterest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt.

Based on our variable rate debt outstanding as of at December 31, 2012. Borrowing levels under these arrangements vary from period to period depending on capital investments2015, and other factors. Future short-termDecember 31, 2014, a hypothetical increase in market interest rates of one-percentage point would have increased annual interest expense by $1.4 million and payments will reflect both future short-term interest rates and borrowing levels.

We performed an interest rate$3.1 million, respectively. This sensitivity analysis as of December 31, 2012 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2012, we had $105.5 million of commercial paper outstanding withwas performed assuming a weighted-average interest rate of 0.27% and $147.0 millionconstant level of variable rate long-term debt outstanding with a weighted-average interest rate of 0.50%. A one-percentage point changeduring the period and an immediate increase in interest rates, would cause our annual interest expense to increase or decrease by approximately $2.5 million.with no other changes for the remainder of the period.

Marketable Securities Return

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.

The fair value of our trust fund assets as of December 31, 2012 wasand expected long-term returns were approximately:

  Millions of Dollars
   
Pension trust funds $1,121.1
Other post-retirement benefits trust funds $194.8

The expected long-term rate of return on plan assets for 2013 is 7.25% and 7.5%, respectively, for the pension and OPEB plans.
(in millions) 
As of
December 31, 2015
 Expected Return on Assets in 2016
Pension trust funds $1,179.3
 7.00%
OPEB trust funds $216.1
 7.25%

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

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


2015 Form 10-K43Wisconsin Electric Power Company
Table of Contents

Economic Conditions:   Conditions

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

Inflation

Inflation:   We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance and new generation in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do

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not believe the impact of general inflation will have a material impact on our future results of operations.

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


POWER THE FUTURE

All of the PTF units have been placed into service and are positioned to provide a significant portion of our future generation needs. The PTF units include PWGS 1, PWGS 2, Oak Creek expansion Unit 1 (OC 1) and OC 2.

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

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

We operate PWGS1, PWGS2, OC1 and OC2 and are authorized by the PSCW to fully recover prudently incurred operating and maintenance costs in our Wisconsin electric rates. As the operator of the units, we may request We Power make capital improvements to or further investments in the units. Under the lease terms, we would expect the costs of any capital improvements or further investments to be added to the lease payments, and ultimately to be recovered in our rates.

We Power assigned its warranty rights to us upon turnover of each of the Oak Creek expansion units. Although the warranty periods for both of the units have expired, we continue to work through outstanding warranty claims with Bechtel. Our warranty claim for the costs incurred to repair steam turbine corrosion damage identified on both units is expected to be resolved through a binding arbitration hearing scheduled for October 2013.

In accordance with the contract between We Power and Bechtel, final acceptance of the units cannot occur until, among other things, all disputes have been settled. Pursuant to the settlement agreement entered into with Bechtel in December 2009, a final payment of $2.5 million per unit will be due upon final acceptance.


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 and electric transmission service rates. The MPSC regulates our retail electric rates in the state of Michigan. We estimate that approximately 88% of our electric revenues are regulated by the PSCW, 6% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC. In Wisconsin, a general rate case is typically filed every two years. All of our natural gas and steam revenues are regulated by the PSCW. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.

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

A net bill increase related to non-fuel costs for our Wisconsin retail electric customers of approximately $70 million (2.6%) for 2013. This amount reflects an offset of approximately $63 million (2.3%) related to the proceeds of a renewable energy cash grant we expect to receive under the NDAA upon completion of our biomass facility currently under construction. Absent this offset, the retail electric rate increase for non-fuel costs is approximately $133 million (4.8%) for 2013.
Absent an adjustment for any remaining energy cash credits, an electric rate increase for our Wisconsin electric customers of approximately $28 million (1.0%) for 2014.
Recovery of a forecasted increase in fuel costs of approximately $44 million (1.6%) for 2013. We will make an annual fuel cost filing, as required, for 2014.

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A rate decrease of approximately $8 million (1.9%) for our natural gas customers for 2013, with no rate adjustment in 2014.
An increase of approximately $1.3 million (6.0%) for our Downtown Milwaukee (Valley) steam utility customers for 2013 and another $1.3 million (6.0%) in 2014.
An increase of approximately $1 million (7.0%) in 2013 and $1 million (6.0%) in 2014, respectively, for our Milwaukee County steam utility customers.

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

2012 Wisconsin Rate Case:   On May 26, 2011, we filed an application with the PSCW to initiate rate proceedings. In lieu of a traditional rate proceeding, we requested an alternative approach, which resulted in no increase in 2012 base rates for our customers. In order for us to proceed under this alternative approach, we requested that the PSCW issue an order that:
Authorizes us to suspend the amortization of $148 million of regulatory costs during 2012, with amortization to begin again in 2013.
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 our settlement of the spent nuclear fuel litigation with the DOE.
Authorizes us to reopen the rate proceeding in 2012 to address, for rates effective in 2013, all issues set aside during 2012.
Schedules a proceeding to establish a 2012 fuel cost plan.

We received a final written order from the PSCW on November 3, 2011. For information related to the proceeding to establish a 2012 fuel cost plan, see 2012 Fuel Recovery Request below.

2012 Michigan Rate Case:On July 5, 2011, we filed a $17.5 million rate increase request with the MPSC, primarily to recover the costs of environmental upgrades and OC 2. Pursuant to Michigan law, we self-implemented a $5.7 million interim electric base rate increase in January 2012. This increase was partially offset by a refund of $2.7million of net proceeds from our settlement of the spent nuclear fuel litigation with the DOE, resulting in a net $3.0million 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 $9.2million annually, effective June 27, 2012, and authorized a 10.1% return on equity.

2010 Wisconsin Rate Case:   In March 2009, we 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 our retail electric rates, which was partially offset by bill credits in 2010;
A decrease of approximately $2.0 million (0.35%) for natural gas service; and
A decrease of approximately $0.4 million (1.65%) for our Valley steam utility customers and a decrease of approximately $0.1 million (0.47%) for our Milwaukee County steam utility customers.

These rate adjustments became effective January 1, 2010. In addition, the PSCW lowered our authorized return on equity from 10.75% to 10.4%.

As part of its final decision in the 2010 rate case, the PSCW authorized us to reopen the docket in 2010 to review updated 2011 fuel costs. In September 2010, we 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. We requested an increase in 2011 Wisconsin retail electric rates of $38.4 million, or 1.4%, related to the increase in 2011 monitored fuel costs as compared to the level of monitored fuel costs then embedded in rates. In December 2010, we reduced our request by approximately $5.2 million. Adjustments by the PSCW reduced the request by an additional $7.8 million. The PSCW issued its final decision, which increased annual Wisconsin retail rates by $25.4 million effective April 29, 2011. The net increase was being driven primarily by an increase in the delivered cost of coal.

2010 Michigan Rate Increase Request:   In July 2009, we filed a $42 million rate increase request with the MPSC,

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primarily to recover the costs of PTF projects. In December 2009, the MPSC approved our modified self-implementation plan to increase electric rates in Michigan by approximately $12 million effective upon commercial operation of OC 1, which occurred on February 2, 2010. On July 1, 2010, the MPSC issued the final order, approving an additional increase of $11.5 million effective July 2, 2010. The combined total increase was $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.

Limited Rate Adjustment Requests

2012 Fuel Recovery Request:In August 2011, we filed a $50 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The primary reasons for the increase were projected higher coal, coal transportation and purchased power costs. This filing was made under the new Wisconsin fuel rules which require annual fuel cost filings. In January 2012, the PSCW issued an order which provided for an increase in fuel costs of approximately $26 million, offset by approximately $26 million from the settlement with the DOE regarding the storage of spent nuclear fuel, resulting in no change in customer bills.

2010 Fuel Recovery Request:   In February 2010, we filed a $60.5 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The increase in fuel and purchased power costs was driven primarily by increases in the price of natural gas compared to the forecasted prices included in the 2010 PSCW rate case order, changes in the timing of plant outages and increased MISO costs. Effective March 25, 2010, the PSCW approved an annual increase of $60.5 million in Wisconsin retail electric rates on an interim basis. On April 28, 2011, the PSCW approved the final increase with no changes.

Other Rate Matters

Oak Creek Air Quality Control System:   In July 2008, we received approval from the PSCW granting us 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). The cost of constructing these facilities has been included in our previous estimates of the costs to implement the Consent Decree with the EPA.

Wisconsin Fuel Rules:   Embedded within our base rates is an amount to recover fuel costs. New fuel rules adopted in December 2010 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. Fuel cost plans approved by the PSCW after January 1, 2011 are subject to the new rules. The deferred fuel costs are subject to an excess revenues test.

Electric Transmission Cost Recovery:   We divested our 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 the state. 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, 2012, we had $114.1 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 a GCRM as approved by the PSCW. Generally, the GCRM allows for a dollar for dollar recovery of gas costs. The GCRM uses a modified one for one method that measures commodity purchase costs against a monthly benchmark which includes a 2% tolerance.

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Costs in excess of this monthly benchmark are subject to additional review by the PSCW before they can be passed through to our customers. The modified one for one is the same method used by the other utilities in Wisconsin.

Renewables, Efficiency and Conservation:   In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. A utility's renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Our baseline renewable energy percentage is 2.27%. Under Act 141, we could not decrease our renewable energy percentage for the years 2006-2009, and for the years 2010-2014, we must increase our renewable energy percentage at least two percentage points to a level of 4.27%. As of December 31, 2012, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. To comply with increasing requirements, we have constructed and contracted for several hundred megawatts of wind generation and are in the process of constructing approximately 50 MW of biomass fueled generation. With the commercial operation of the Glacier Hills Wind Park in December 2011, and assuming the biomass project is completed on schedule, we expect to be in compliance with Act 141's 2015 standard. We have entered into agreements for renewable energy credits which should allow us to remain in compliance with Act 141 through 2019. If market conditions are favorable, we may purchase more renewable energy credits. See Renewable Energy Portfolio discussion below for additional information regarding the development of renewable energy generation.

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 2012. The funding required by Act 141 for 2013 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.

Renewable Energy Portfolio:   The Blue Sky Green Field wind farm project, which has 88 turbines with an installed capacity of 145 MW, commenced commercial operation in May 2008. The Glacier Hills Wind Park, which has 90 turbines with an installed capacity of 162 MW, commenced commercial operation in December 2011. The final cost of the Glacier Hills Wind Park is approximately $347 million, excluding AFUDC.

We are constructing a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site. Wood waste and wood shavings will be used to produce approximately 50 MW of renewable electricity and will also support Domtar's sustainable papermaking operations. Construction commenced in June 2011. We currently expect to invest between $245 million and $255 million, excluding AFUDC, in the plant. We are targeting completion of the facility by the end of 2013.

On December 21, 2012, we purchased Montfort from NextEra Energy Resources for $27 million. Montfort has 20 turbines with an installed capacity of 30 MW.


ELECTRIC SYSTEM RELIABILITY

We continue to upgrade our electric distribution system, including substations, transformers and lines. We had

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adequate capacity to meet all of our firm electric load obligations during 2012 and 2011. 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 all of our firm load obligations during 2013. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures.


ENVIRONMENTAL MATTERS

Overview

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include but are not limited to current and future regulation of: (1) air emissions such as SO2, NOx, 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 are continuing to pursue a proactive strategy to manage our environmental compliance obligations, including: (1) developing additional sources of renewable electric energy supply; (2) reviewing water quality matters such as discharge limits and cooling water requirements and implementing improvements to our cooling water intake systems as needed; (3) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules; (4) implementing a Consent Decree with the EPA to reduce emissions of SO2 and NOx by more than 65% by 2013; (5) converting the fuel source for VAPP from coal to natural gas; (6) continuing the beneficial use of ash and other solid products from coal-fired generating units; and (7) conducting the clean-up of former manufactured gas plant sites.

Air Quality

EPA Consent Decree:   In April 2003, we reached a Consent Decree with the EPA, in which we agreed to significantly reduce air emissions from certain of our coal-fired generating facilities. The U.S. District Court for the Eastern District of Wisconsin approved the amended Consent Decree and entered it in October 2007. For further information, see Note P -- Commitments and Contingencies in the Notes to 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 January 2010, the EPA announced its decision to further lower the 2008 8-hour ozone standard. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard until 2013.

Fine Particulate Standard:    In 2009, the EPA designated three counties in southeast Wisconsin (Milwaukee, Waukesha and Racine) as not meeting the daily standard for PM2.5. In April 2012, the EPA proposed to determine that these three counties meet the PM2.5 standard, and proposed to suspend the requirement that the state submit a State Implementation Plan (SIP) including reasonably available control technology (RACT) regulations. On December 28 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

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construction permitting requirements and emission offset provisions. On December 14, 2012, the EPA issued a revised and more stringent annual PM2.5 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. These standards, as modified, represent a significant change from the previous SO2 standards. The implementation guidance for the new standards, 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 withdrawn this implementation guidance, and has indicated it is going to propose new implementation guidance through a rulemaking in 2013.

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 standards remain in place, we believe that we would not need to make significant capital expenditures at the majority of our generation units because of prior investments in pollution control equipment and technology. However, we believe that the new standards will require us to retrofit PIPP in the Upper Peninsula of Michigan with additional environmental controls. In November 2012, we entered into a joint ownership agreement with Wolverine whereby Wolverine will pay for the installation of air quality control systems at PIPP and will receive a minority ownership interest in the plant in return. This transaction is subject to the receipt of regulatory approvals from various state and federal regulatory agencies, including the MPSC, PSCW and FERC. We began submitting applications for these regulatory approvals in February 2013.

The new standards 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. While we are continuing to evaluate the impact of the rule on the operation of our existing coal-fired generation facilities, as well as alternatives for complying with the rule, we currently estimate our capital cost to comply with this rule will be approximately $8.0 million to $12.5 million. Based upon our review of the rules and plans to convert the VAPP from coal to natural gas fuel, we currently anticipate that only the PIPP will require modifications, which we expect will be funded by Wolverine under the joint ownership agreement. We believe that our clean air strategy, including the environmental upgrades that have been constructed and that are currently under construction at our other coal-fired plants, positions those other plants well to meet the rule's requirements.

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 NOx and SO2 that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation scheme. 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 these proposed revisions, however, the 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 had requested the court to re-hear the case; however, on January

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24, 2013, the court denied the EPA's request. The EPA has 90 days from the date of the D.C. Circuit Court's decision to appeal to the United States Supreme Court.

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 PM2.5 or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia.

In June 2012, the EPA promulgated a Federal Implementation Plan that approves reliance on the CSAPR to satisfy electric generating unit BART requirements for NOx 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 NOx and SO2.

Because of the court decision to vacate CSAPR and potential continuing litigation on that decision, we will not be able to determine final regional haze requirements for NOx and SO2 at our facilities until judicial review of CSAPR is completed and any subsequent rulemaking activities required as a result of that review 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:

Working with We Power to repower the Port Washington Power Plant from coal to natural gas-fired combined cycle units.
Adding coal-fired units to our generating fleet as part of the Oak Creek expansion that are the most thermally efficient coal units in our system.
Increasing investment in energy efficiency and conservation.
Adding renewable capacity and continuing to offer the Energy for Tomorrow® renewable energy program.
Planning to convert the fuel source at the VAPP from coal to natural gas.
Retirement of coal units 1-4 at the Presque Isle Power Plant.

Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas emissions. The President's administration recently reaffirmed that regulation of greenhouse gas emissions continues to be a top priority. Although legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards failed to pass in the U.S. Congress, we expect such legislation to be considered in the future. Any mandatory restrictions on our CO2 emissions that may be adopted by Congress or Wisconsin's or Michigan's legislature could result in significant compliance costs that could affect future results of operations, cash flows and financial condition.

While climate change legislation has yet to be adopted, the EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. In March 2012, the EPA proposed new source performance standards pertaining to greenhouse gas emissions from certain new power plants, including coal-fired plants, based on the performance of combined cycle natural gas-fueled generating plants.

We expect the EPA to attempt to address performance standards for existing generating units in 2013. 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.


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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 2011, we reported CO2 equivalent emissions of approximately 22.4 million metric tonnes to the EPA, compared with approximately 20.9 million metric tonnes for 2010. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO2 equivalent emissions of approximately 18.1 million metric tonnes to the EPA for 2012. 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 2011, we reported approximately 3.8 million metric tonnes of CO2 to the EPA related to our distribution and sale of natural gas, compared with approximately 3.6 million metric tonnes for 2010. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO2 emissions of approximately 3.3 million metric tonnes to the EPA for 2012.

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 $60 million and $65 million and, subject to receipt of PSCW approval and a construction air permit from the WDNR, anticipate that the conversion will be completed by the end of 2015 or early 2016. We expect to file for a Certificate of Authority from the PSCW during the second quarter of 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. For further information, see Note P -- 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, which must be finalized by June 27, 2013. Once the rule is final, 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.

On December 27, 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,

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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 federal guidelines regulate waste water discharges from our power plant processes, and are under review by the EPA. The EPA rules are currently expected to be proposed by the end of April 2013, and finalized by the end of May 2014. After the promulgation of final rules, it is expected that the WDNR will need to modify Wisconsin's rules. The existing Wisconsin state rules for waste water discharge are very stringent, and therefore, the systems that have been installed at the Pleasant Prairie Power Plant and the Oak Creek Power Plant use advanced technology. We are unable to determine the impact, if any, of these rules on our facilities at this time.

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 the earliest the EPA will take action on a final rule is the first quarter 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 are continuing to pursue an EPA determination on acceptable use for coal ash as a non-hazardous secondary material based on our processing of the materials prior to reburning as currently allowed under the Secondary Materials Rule.Both of these rules have the potential to negatively affect our ability to reburn coal ash from power plants and landfills.

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 P -- 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 P -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.


LEGAL MATTERS

Cash Balance Pension Plan:   See Note P -- Commitments and Contingencies in the Notes to Consolidated Financial Statements for information regarding a lawsuit filed against the Plan.

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 continue to make claims against us for loss of milk production and other damages to livestock allegedly caused by stray voltage and ground currents resulting from the operation of our electrical system, even though that electrical system has been operated within the parameters of the PSCW's order. The Wisconsin Supreme Court has rejected the arguments that, if a utility company's measurement of stray voltage is below the

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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.


NUCLEAR OPERATIONS

Used Nuclear Fuel Storage and Disposal:   During our ownership of Point Beach, we were authorized by the PSCW to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their original operating licenses, but not to exceed the original 48-canister capacity of the dry fuel storage facility. The original operating licenses were set to expire in October 2010 for Unit 1 and in March 2013 for Unit 2 before they were renewed and extended by the United States Nuclear Regulatory Commission in December 2005.

Temporary storage alternatives at Point Beach are necessary until the DOE takes ownership of and permanently removes the used fuel as mandated by the Nuclear Waste Policy Act of 1982, as amended in 1987. The Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of such waste and fuel. Effective January 31, 1998, the DOE failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which we paid a total of $215.2 million into the Nuclear Waste Fund over the life of our ownership of Point Beach.

In August 2000, the United States Court of Appeals for the D.C. Circuit ruled in a lawsuit brought by Maine Yankee and Northern States Power Company that the DOE's failure to begin performance by January 31, 1998 constituted a breach of the Standard Contract, providing clear grounds for filing complaints in the Court of Federal Claims. Consequently, we filed a complaint in November 2000 against the DOE in the Court of Federal Claims. In October 2004, the Court of Federal Claims granted our motion for summary judgment on liability. The Court held a trial during September and October 2007 to determine damages. In December 2009, the Court ruled in our favor, granting us more than $50 million in damages. In February 2010, the DOE filed an appeal. 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 as part of the PSCW's approval of our 2012 fuel recovery request and the MPSC's approval of our interim order for the 2012 Michigan rate case.


INDUSTRY RESTRUCTURING AND COMPETITIONIndustry Restructuring

Electric Utility Industry

The regulated energy industry continues to experience significant changes. FERC continues to support large RTOs, which affectaffects 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 accesschoice might be implemented, if at all, in Wisconsin; however,Wisconsin. However, Michigan has adopted retail choice which potentially affects our Michigan operations.choice.

Restructuring in Wisconsin:Wisconsin

Electric utility revenues in Wisconsin are regulated by the PSCW. Due to many factors, including relatively competitive electric rates charged by the state's electric utilities, theThe 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:   Our Michigan

Under Michigan law, our retail customers are allowed to remain with their regulated utility at regulated rates ormay choose an alternative electric supplier to provide power supply service. WeSome of our small retail customers have maintainedswitched to an alternative electric supplier. The law limits customer choice to 10% of our generation capacity and distribution assets andMichigan retail load, but the two iron ore mines in our service territory are excluded from this cap. See Note 20, Michigan Settlement, for information on the mines' ability to switch to an alternative electric supplier. When a customer switches to an alternative electric supplier, we continue to provide regulated service as we have in the past. We continue providing distribution and customer service functions regardless of the customer's power supplier.

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Competition and customer switching to alternative suppliers in our service territories in Michigan has been limited. However, the additional competitive pressures resulting from retail access could lead to a loss of customers and our incurring stranded costs. A loss of customers could also have a material adverse effect on our results of operations and cash flows.

Electric Transmission and Energy Markets

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

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

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

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through Auction Revenue Rights (ARRs) and Financial Transmission Rights (FTRs). ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2012 through May 31, 2013. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.customer.

Natural Gas Utility Industry

Restructuring in Wisconsin:Wisconsin

The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect the changinga 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 segmentsclasses with workably competitive market choices and has adopted standards for transactions between a utility and its natural gas marketing affiliates. All of our Wisconsin customer classes have workably competitive market choices and, therefore, can purchase natural gas directly from a third party supplier. However, work on deregulation of the natural 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 recently received a new air construction permit from the WDNR to modify the Oak Creek expansion units for potential future use of sub-bituminous coal. We are scheduled to begin testing sub-bituminous coal in various combinations with bituminous coal in 2013 to identify any equipment limitations that should be considered prior to filing with the PSCW for a Certificate of Authority to make the fuel flexibility modifications. In February 2013, the Sierra Club and the Midwest Environmental Defense Center filed for a contested case hearing with the WDNR to challenge the issuance of the air construction permit.

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

2015 Form 10-K6244Wisconsin Electric Power Company
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Environmental Matters

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule (CAIR). The purpose of the CSAPR was to limit the interstate transport of emissions of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allocation plan and allowance trading scheme. The rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals) and CAIR was implemented during the stay period. In August 2012, the D.C. Circuit Court of Appeals issued a ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court (Supreme Court). In April 2014, the Supreme Court issued a decision largely upholding CSAPR and remanded it to the D.C. Circuit Court of Appeals for further proceedings. In October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The compliance deadlines were also changed by three years, so that Phase I emissions budgets apply in 2015 and 2016, and Phase 2 emissions budgets will apply to 2017 and beyond.

In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and plans to issue a final rule by August 2016. Starting in 2017, this proposed rule would reduce ozone season (May 1 through September 30) NOxemissions from power plants in 23 states in the eastern United States. In this rule, the EPA is proposing to update Phase II CSAPR NOxozone season budgets for electric generating units in the 23 states. An approximate 60% reduction in NOxemissions is proposed for Wisconsin and an approximate 29% reduction is proposed for Michigan, beginning in May 2017. Additional investments in controls and/or shifts in generation may be required depending upon the final outcome of the rule. We submitted comments to the EPA on the potential impacts of the rule.

See Note 15, Commitments and Contingencies, for a discussion of additional environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, renewable energy requirements, and climate change.

Other Matters

American Transmission Company Allowed Return On Equity Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 12, 2013. The FERC conducted hearings in August 2015, and the administrative law judge (ALJ) issued an initial decision in December 2015. The ALJ's initial decision recommended that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The ALJ's recommendation is not binding to the FERC. A FERC order related to this complaint is expected during the fourth quarter of 2016.

In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to the filing date of the complaint. The FERC conducted hearings in February 2016 with respect to this second complaint, and an initial decision is expected by June 30, 2016.

In October 2014, the FERC issued an order, in regard to a similar complaint, reducing the base ROE for New England transmission owners from their existing rate of 11.14% to 10.57%. In this order, the FERC used a revised method for determining the appropriate ROE for FERC-jurisdictional electric utilities. The FERC expects its new methodology will narrow the "zone" of reasonable returns on equity. The FERC has stated that it expects future decisions on pending complaints related to similar ROE issues to be guided by the New England transmission decision.

Any change to ATC's ROE could result in lower equity earnings and distributions from ATC in the future. We are currently unable to determine how the FERC may rule in these complaints. However, we believe it is probable that refunds will be required upon resolution of these issues. Based on the ALJ's initial decision in December 2015, ATC reduced its earnings, which resulted in us recognizing lower earnings from our investment in ATC.


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Wisconsin Power and Light's (WP&L) Riverside Energy Center Facility

In April 2015, WP&L filed a CPCN application with the plant has not been operatedPSCW for approval to useconstruct an approximate 650 MW natural gas-fired combined-cycle generating unit in Beloit, Wisconsin. Recent construction proposals received by WP&L indicate that the potential additionalunit could generate up to 700 MWs. In the third quarter of 2015, we, along with our affiliated utility, Wisconsin Public Service Corporation (WPS), requested and received intervention in this proceeding. As intervenors, we and WPS proposed purchased power agreement alternatives to the new generating unit. In December 2015, we entered into a settlement agreement with WPS and WP&L that was approved by the PSCW. Based on the settlement agreement, the generating unit cannot become commercially operational before June 1, 2020. In addition, WP&L must enter into a purchased power agreement with us for MISO planning years 2017, 2018, and 2019, whereby we will sell and WP&L will purchase capacity and energy at certain agreed upon prices. WPS will have the WDNR has indicated that it now considers this maintenanceoption to be a modification requiring a construction permit. The WDNR issued a NOVpurchase an undivided ownership interest of up to us on January 7, 2013 alleging violations100 MWs of generating capacity from the unit during the first two years of operation and up to an aggregate 200 MWs of generating capacity during the third and fourth years of operation. Other major terms of the new source review rulessettlement included agreement on ownership of future natural gas units and certain Wisconsin environmental rules. At the same time, the WDNR also issuednegotiation of a renewable generation joint development plan.

Bonus Depreciation Provisions

The Protecting Americans from Tax Hikes Act of 2015 was signed into law on December 18, 2015. This act extended 50% bonus depreciation to assets placed in service during 2015 through 2017, 40% bonus depreciation to assets placed in service during 2018, and 30% bonus depreciation to assets placed in service during 2019. Bonus depreciation is an administrative orderadditional amount of deductible depreciation that prohibits us from operating PSGS Units 1is awarded above and 4 until the earlier of: (1) Units 1 and 4 achieve the applicable NOx emission rates; (2) the Wisconsin regulations are revised so that Units 1 and 4 can achieve the emission limits or are no longer subjectbeyond what would normally be available. Due to the limits; (3) the alleged modification is resolved through a consent decree;increase in federal tax depreciation for 2014 and prior years, we did not make federal income tax payments for 2014 or (4) until a court decides that the blade replacement project was not a major modification. We are presently evaluating alternative approaches to return these peaking units to service, and expect that Units 1 and 4 will remain out of service until at least 2014. In addition, we may be subject to fines and penalties. In February 2013, the Sierra Club filed for a contested case hearing with the WDNR in connection with the administrative order.
We continue to evaluate the impact, if any, that this outage may have on network reliability, and to determine whether we will need to find alternative sources of generation in the short-term to replace the generation from these units during the temporary outage.
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.

2013.

ACCOUNTING DEVELOPMENTS

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

Section 1603 Renewable Energy Treasury Grant:   We expect to receive a treasury grant of approximately $72 million related to the construction of our biomass facility in Rothschild, Wisconsin. We expect to recognize the treasury grant when the plant is placed into service, which is when we expect to conclude it is probable we will receive the grantPolicies and when we can reasonably estimate the grant amount. The expected receipt of the treasury grant has been taken into consideration by the PSCW in connection with our electric rates that became effective January 1, 2013. Our Wisconsin retail electric customers will receive bill credits in 2013 and 2014. When we recognize the treasury grant as income, we will also defer a portion of the grant associated with the future bill credits and the deferred grant will be amortized to income to match the bill credits to the customers.

International Financial Reporting Standards:   During 2009, the SEC announced a "roadmap" for the potential use by U.S. registrants of IFRS instead of GAAP. The SEC issued a Work Plan to consider specific areas and factors relevant to a determination of whether, when and how the current financial reporting system for U.S. registrants should be transitioned to a system incorporating IFRS. In July 2012, the SEC Staff issued its final report on the Work Plan. The report does not include a final policy or decision as to whether IFRS might be incorporated into the financial reporting system for U.S. registrants, or how such incorporation should occur. The Staff report indicates that additional analysis is necessary before any SEC decision is made about incorporating IFRS into the U.S. financial reporting system. The timing of this additional activity is currently unknown. To the extent the SEC determines to adopt IFRS, if at all, we are currently unable to determine when we would be required to begin using IFRS.

CRITICAL ACCOUNTING ESTIMATESEstimates

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

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results of operations and that require management's most difficult, subjective or complex judgments:

Regulatory Accounting:We operate under rates established by statePension 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 companies would expense and accrue liabilities that non-regulated companies would not. As of December 31, 2012, we had $1,481.2 million in regulatory assets and $601.8 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.Other Postretirement Employee Benefits

Pension and OPEB:   Our reportedThe costs of providing non-contributorynoncontributory defined benefit pension benefits (describedand OPEB, described in Note M --14, Employee Benefits, in the Notes to Consolidated Financial Statements) are dependent uponon numerous factors resulting from actual plan experience and assumptions ofregarding future experience.

Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Changes made to the provisions of the plans may also impact currentPension and future pension costs. PensionOPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and the discount rates, used in determining the projected benefit obligation and pension costs.

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

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

Pension Plan Impact on
Actuarial Assumption Annual Cost
  (Millions of Dollars)
   
0.5% decrease in discount rate and lump sum conversion rate $4.2
0.5% decrease in expected rate of return on plan assets $4.9

In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note M -- 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 andexpected health care cost trends. Changes made to the plan provisions of the plans may also impact current and future pension and OPEB costs. OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets

Pension 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 and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased other post-retirementbenefit costs in future periods. Similar to accounting for pension plans, our regulators have adopted accounting guidance for compensation related to retirement benefits for rate-making purposes.

The following table reflects OPEB plan sensitivities associated withWe believe that such changes in certain actuarial assumptions bycosts would be recovered or refunded through the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.ratemaking process.


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The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
Actuarial Assumption
(in millions, except percentages)
 Percentage-Point Change in Assumption Impact on Projected Benefit Obligation 
Impact on 2015
Pension Cost
Discount rate (0.5) $72.4
 $4.6
Discount rate 0.5 (65.6) (4.9)
Rate of return on plan assets (0.5) N/A
 6.0
Rate of return on plan assets 0.5 N/A
 (6.0)

The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
Actuarial Assumption
(in millions, except percentages)
 Percentage-Point Change in Assumption 
Impact on Postretirement
Benefit Obligation
 
Impact on 2015 Postretirement
Benefit Cost
Discount rate (0.5) $21.6
 $0.8
Discount rate 0.5 (19.4) (0.6)
Health care cost trend rate (0.5) (13.0) (1.4)
Health care cost trend rate 0.5 14.7
 1.6
Rate of return on plan assets (0.5) N/A
 1.1
Rate of return on plan assets 0.5 N/A
 (1.1)

In the fourth quarter of 2014, the Society of Actuaries published a new set of mortality tables, which updated life expectancy assumptions. We have adjusted the tables to better reflect our plan-specific mortality experience and other general assumptions. We have incorporated the revised mortality tables into the projected pension and OPEB obligations at December 31, 2015.

The discount rates are selected based on hypothetical bond portfolios consisting of noncallable (or callable with make-whole provisions), noncollateralized, high-quality corporate bonds with maturities between 0 and 30 years. The bonds are generally rated "Aa" with a minimum amount outstanding of $50.0 million. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.

We establish our expected return on asset assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.00% in 2015 and 7.25% in both 2014 and 2013, respectively. The actual rate of return on pension plan assets, net of fees, was (0.6)%, 6.17%, and 10.92%, in 2015, 2014, and 2013, respectively.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 14, Employee Benefits.

Regulatory Accounting

Our electric and natural gas utility segments follow the guidance under the Regulated Operations Topic of the FASB ASC. Our financial statements reflect the effects of the ratemaking principles followed by the various jurisdictions regulating us. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings at our electric and natural gas utility segments, and the status of any pending or potential deregulation legislation.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our electric and natural gas utility segments' operations no longer meet the criteria for application. Our regulatory assets and liabilities would be

ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)20122015 Form 10-K47Wisconsin Electric Power Company
Table of Contents

written off as a charge to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2015, we had $1,855.9 million in regulatory assets and $741.2 million in regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information.

OPEB Plan Impact on
Actuarial Assumption Annual Cost
  (Millions of Dollars)
   
0.5% decrease in discount rate $2.5
0.5% decrease in health care cost trend rate in all future years $(3.2)
0.5% decrease in expected rate of return on plan assets $0.9
Unbilled Revenues

Unbilled Revenues:   We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total operating revenues during 20122015 of approximately $3.6$3.9 billion included accrued revenues of $213.8$200.2 million as of December 31, 2012.

2015.

Income Tax Expense

We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing consolidated financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to the provision for income taxes in our income statements.

Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(k), Income Taxes, and Note 13, Income Taxes, for a discussion of accounting for income taxes.

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 77. of this report, as well as Note K --1(o), Derivative Instruments, and Note L --1(n), Fair Value Measurements, in the Notes to Consolidated Financial Statements, for information concerning potential market risks to which we are exposed.

2015 Form 10-K6548Wisconsin Electric Power Company
Table of Contents
2012 Form 10-K

ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
Year Ended December 31
      
 2012 2011 2010
 (Millions of Dollars)
      
Operating Revenues$3,613.3
 $3,727.6
 $3,456.7
      
Operating Expenses     
Fuel and purchased power1,103.8
 1,174.5
 1,104.7
Cost of gas sold227.7
 306.2
 316.0
Other operation and maintenance1,327.8
 1,447.6
 1,432.5
Depreciation and amortization257.6
 220.3
 216.2
Property and revenue taxes113.1
 105.4
 96.5
Total Operating Expenses3,030.0
 3,254.0
 3,165.9
      
Amortization of Gain—
 —
 198.4
      
Operating Income583.3
 473.6
 489.2
      
Equity in Earnings of Transmission Affiliate57.6
 54.9
 52.7
Other Income and Deductions, net32.3
 62.1
 39.8
Interest Expense, net113.2
 94.2
 101.5
      
Income Before Income Taxes560.0
 496.4
 480.2
      
Income Tax Expense192.7
 156.8
 164.8
      
Net Income367.3
 339.6
 315.4
      
Preferred Stock Dividend Requirement1.2
 1.2
 1.2
      
Earnings Available for Common Stockholder$366.1
 $338.4
 $314.2
      
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



66Wisconsin Electric Power Company
2012 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
 
ASSETS
    
 2012 2011
 (Millions of Dollars)
Property, Plant and Equipment   
Electric$8,171.0
 $7,088.7
Gas950.3
 910.0
Steam95.5
 93.4
Common295.3
 264.0
Other56.8
 60.1
 9,568.9
 8,416.2
Accumulated depreciation(3,117.0) (2,964.7)
 6,451.9
 5,451.5
Construction work in progress289.1
 902.4
Leased facilities, net2,340.2
 2,428.2
Net Property, Plant and Equipment9,081.2
 8,782.1
    
Investments   
Equity investment in transmission affiliate332.6
 307.5
Other0.3
 0.2
Total Investments332.9
 307.7
    
Current Assets   
Cash and cash equivalents34.1
 12.7
Restricted cash2.7
 45.5
Accounts receivable, net of allowance for   
doubtful accounts of $36.7 and $36.9226.3
 274.2
Accounts receivable from related parties6.1
 36.5
Income taxes receivable11.0
 99.4
Accrued revenues213.8
 200.5
Materials, supplies and inventories312.2
 319.2
Prepayments136.3
 130.7
Other51.5
 51.3
Total Current Assets994.0
 1,170.0
    
Deferred Charges and Other Assets   
Regulatory assets1,452.2
 1,236.2
Other162.3
 165.3
Total Deferred Charges and Other Assets1,614.5
 1,401.5
    
Total Assets$12,022.6
 $11,661.3
    
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.


67Wisconsin Electric Power Company
2012 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
 
CAPITALIZATION AND LIABILITIES
    
 2012 2011
 (Millions of Dollars)
Capitalization   
Common equity$3,366.4
 $3,177.1
Preferred stock30.4
 30.4
Long-term debt2,216.7
 2,267.6
Capital lease obligations2,703.1
 2,716.5
Total Capitalization8,316.6
 8,191.6
    
Current Liabilities   
Long-term debt and capital lease obligations due currently357.0
 37.9
Short-term debt105.5
 352.0
Subsidiary note payable to Wisconsin Energy23.4
 26.8
Accounts payable306.8
 265.2
Accounts payable to related parties93.4
 94.6
Accrued payroll and benefits75.4
 73.2
Other110.2
 173.4
Total Current Liabilities1,071.7
 1,023.1
    
Deferred Credits and Other Liabilities   
Regulatory liabilities600.3
 658.1
Deferred income taxes - long-term1,533.6
 1,284.0
Pension and other benefit obligations189.2
 278.8
Other311.2
 225.7
Total Deferred Credits and Other Liabilities2,634.3
 2,446.6
    
Commitments and Contingencies (Note P)
 
    
Total Capitalization and Liabilities$12,022.6
 $11,661.3
    
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



68Wisconsin Electric Power Company
2012 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
       
  2012 2011 2010
  (Millions of Dollars)
Operating Activities      
Net income $367.3
 $339.6
 $315.4
Reconciliation to cash      
Depreciation and amortization 263.6
 223.6
 224.2
Amortization of gain —
 —
 (198.4)
Deferred income taxes and investment tax credits, net 194.1
 265.1
 69.6
Contributions to qualified benefit plans (92.9) (275.1) —
Change in - Accounts receivable and accrued revenues 64.3
 (9.0) (44.0)
Inventories 7.0
 2.6
 (0.3)
Other current assets 6.9
 (23.5) 17.0
Accounts payable 41.4
 41.4
 23.0
Accrued income taxes, net 89.4
 (85.4) (65.5)
Deferred costs, net 9.2
 25.9
 25.9
Other current liabilities (2.4) 23.9
 6.6
Other, net (140.9) 14.8
 51.7
Cash Provided by Operating Activities 807.0
 543.9
 425.2
       
Investing Activities      
Capital expenditures (575.8) (706.6) (617.3)
Investment in transmission affiliate (13.8) (5.8) (4.6)
Proceeds from asset sales 3.3
 41.5
 5.5
Change in restricted cash 42.8
 (37.2) 186.2
Other, net (62.1) (54.0) (40.6)
Cash Used in Investing Activities (605.6) (762.1) (470.8)
       
Financing Activities      
Dividends paid on common stock (179.6) (239.6) (179.6)
Dividends paid on preferred stock (1.2) (1.2) (1.2)
Issuance of long-term debt 250.0
 300.0
 —
Change in total short-term debt (249.9) 140.7
 117.9
Capital contribution from parent —
 —
 100.0
Other, net 0.7
 7.7
 13.5
Cash (Used In) Provided by Financing Activities (180.0) 207.6
 50.6
       
Change in Cash and Cash Equivalents 21.4
 (10.6) 5.0
       
Cash and Cash Equivalents at Beginning of Year 12.7
 23.3
 18.3
       
Cash and Cash Equivalents at End of Year $34.1
 $12.7
 $23.3
       
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.


69Wisconsin Electric Power Company
2012 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
     
  2012 2011
  (Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)   
Common stock - $10 par value; authorized   
65,000,000 shares; outstanding - 33,289,327 shares$332.9
 $332.9
Other paid in capital944.7
 941.9
Retained earnings2,088.8
 1,902.3
Total Common Equity3,366.4
 3,177.1
     
Preferred Stock   
Six Per Cent. Preferred Stock - $100 par value;   
authorized 45,000 shares; outstanding - 44,498 shares4.4
 4.4
Serial preferred stock -   
$100 par value; authorized 2,286,500 shares; 3.60% Series   
redeemable at $101 per share; outstanding - 260,000 shares26.0
 26.0
$25 par value; authorized 5,000,000 shares; none outstanding—
 —
Total Preferred Stock30.4
 30.4
     
Long-Term Debt    
Debentures (unsecured)4.50% due 2013300.0
 300.0
 6.00% due 2014300.0
 300.0
 6.25% due 2015250.0
 250.0
 4.25% due 2019250.0
 250.0
 2.95% due 2021300.0
 300.0
 6-1/2% due 2028150.0
 150.0
 5.625% due 2033335.0
 335.0
 5.70% due 2036300.0
 300.0
 3.65% due 2042250.0
 —
 6-7/8% due 2095100.0
 100.0
     
Notes (secured, nonrecourse)4.81% effective rate due 20302.0
 2.0
     
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 held by us (see Note I)(147.0) (147.0)
Unamortized discount, net (20.3) (19.4)
Long-term debt due currently (300.0) —
Total Long-Term Debt 2,216.7
 2,267.6
     
Obligations Under Capital Leases (see Note I)2,703.1
 2,716.5
     
Total Capitalization $8,316.6
 $8,191.6
     

(a)     Variable interest rate as of December 31, 2012.

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

70Wisconsin Electric Power Company
2012 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON EQUITY
        
 Common Other Paid Retained  
 Stock In Capital Earnings Total
 (Millions of Dollars)
        
Balance - December 31, 2009$332.9
 $802.4
 $1,668.9
 $2,804.2
Net income    315.4
 315.4
Cash dividends       
Common stock    (179.6) (179.6)
Preferred stock    (1.2) (1.2)
Capital contribution from parent  100.0
   100.0
Stock-based compensation  7.0
   7.0
Tax benefit of exercised stock options allocated from Parent  19.3
   19.3
Balance - December 31, 2010332.9
 928.7
 1,803.5
 3,065.1
Net income    339.6
 339.6
Cash dividends       
Common stock    (239.6) (239.6)
Preferred stock    (1.2) (1.2)
Stock-based compensation  2.6
   2.6
Tax benefit of exercised stock options allocated from Parent  10.6
   10.6
Balance - December 31, 2011332.9
 941.9
 1,902.3
 3,177.1
Net income    367.3
 367.3
Cash dividends       
Common stock    (179.6) (179.6)
Preferred stock    (1.2) (1.2)
Stock-based compensation  2.8
   2.8
Balance - December 31, 2012$332.9
 $944.7
 $2,088.8
 $3,366.4
        
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



71Wisconsin Electric Power Company
2012 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:Wisconsin Electric Power Company (Wisconsin Electric, the Company, our, us or we), a subsidiary of Wisconsin Energy, is an electric, gas and steam utility which services electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metropolitan Milwaukee, Wisconsin. We consolidate our wholly-owned subsidiary, Bostco. Bostco had total assets of $30.2 million and $33.9 million as of December 31, 2012 and 2011, respectively.

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

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

Reclassifications:   Certain prior period amounts have been reclassified on a basis consistent with the current period financial statement presentation.

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. Beginning in January 2011, the electric fuel rules in Wisconsin allow us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the approved fuel cost plan. The deferred under-collected amounts are subject to an excess revenues test.

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

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

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

Other Income and Deductions, net 2012 2011 2010
  (Millions of Dollars)
       
AFUDC - Equity $34.9
 $59.2
 $32.4
Gain on Property Sales 1.3
 2.4
 4.5
Other, net (3.9) 0.5
 2.9
Total Other Income and Deductions, net $32.3
 $62.1
 $39.8

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.

72Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K


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 2012, 2011and2010.

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

We collect in our rates amounts representing future removal costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $561.3 million as of December 31, 2012 and $566.2 million as of December 31, 2011.

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

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

  2012 2011 2010
  (Millions of Dollars)
       
AFUDC - Debt $14.5
 $24.7
 $13.5
AFUDC - Equity $34.9
 $59.2
 $32.4

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

Materials, Supplies and Inventories 2012 2011
  (Millions of Dollars)
     
Fossil Fuel $165.3
 $169.0
Materials and Supplies 118.6
 110.0
Natural Gas in Storage 28.3
 40.2
Total $312.2
 $319.2

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. Regulatory assets associated with pension and OPEB expenses are amortized as a component of pension and OPEB expense. Regulatory assets and liabilities that are expected to be amortized within 1 year are recorded as current on the balance sheet. 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.

73Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K


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

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

Restricted Cash:   As of December 31, 2012 and 2011, restricted cash consists of the settlement we received from the DOE during the first quarter of 2011, which is being returned, net of costs incurred, to customers. As of December 31, 2012, all restricted cash is classified as current.

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

Restrictions:Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. We do not believe that these restrictions will materially affect our operations. For further information, see Note H.

Investments:   We account for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 23.0% in ATC as of December 31, 2012 and 2011. 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 O.

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

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

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

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

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

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

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

Wisconsin Energy estimates the fair value of stock options using the binomial pricing model. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than 10 years from the grant date. Excess tax benefits are reported as a financing cash inflow. In addition, Wisconsin Energy reports unearned stock-based compensation associated with non-vested restricted stock and performance awards within other paid in capital in its Consolidated Statements of Common Equity. For a discussion of the impacts to our Consolidated Financial Statements, see Note H.


74Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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

 2012 2011 2010
Risk-free interest rate0.1% - 2.0% 0.2% - 3.4% 0.2% - 3.9%
Dividend yield3.9% 3.9% 3.7%
Expected volatility19.0% 19.0% 20.3%
Expected life (years)5.9 5.5 5.9
Expected forfeiture rate2.0% 2.0% 2.0%
Weighted-average fair value     
of stock options granted$3.34 $3.17 $3.36


B -- RECENT ACCOUNTING PRONOUNCEMENTS

Offsetting Assets and Liabilities: In December 2011, The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-11, Disclosures about Offsetting Assets and Liabilities. The guidance requires enhanced disclosures about derivatives. Both gross and net information related to eligible transactions will be 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. Adoption of this guidance may result in additional disclosures related to derivatives beginning in the first quarter of 2013.


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, 2012 and 2011, we had approximately $4.8 million and $8.0 million, respectively, of net regulatory assets that were not earning a return.

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:

  2012 2011
  (Millions of Dollars)
Regulatory Assets    
Deferred unrecognized pension costs $555.0
 $476.0
Deferred plant related -- capital leases 419.8
 326.3
Escrowed electric transmission costs 114.1
 118.3
Deferred income tax related 173.1
 118.0
Deferred unrecognized OPEB costs 29.2
 68.0
Other, net 190.0
 149.5
Total regulatory assets $1,481.2
 $1,256.1
     
Regulatory Liabilities    
Deferred cost of removal obligations $561.3
 $566.2
Other, net 40.5
 105.0
Total regulatory liabilities $601.8
 $671.2

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

75Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

amortization of the leased asset and the imputed interest expense.

Regulatory assets and liabilities that are expected to be amortized within one year are recorded as current on the balance sheet.


D -- DIVESTITURES

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.


E -- ASSET RETIREMENT OBLIGATIONS

The following table presents the change in our AROs during 2012 and 2011:

  2012 2011
  (Millions of Dollars)
     
Balance as of January 1 $52.9
 $50.8
Liabilities Incurred —
 —
Liabilities Settled (14.0) (2.2)
Accretion 2.6
 2.8
Cash Flow Revisions —
 1.5
Balance as of December 31 $41.5
 $52.9


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 10 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 $256.3 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 2012, 2011 and 2010 were $45.8 million, $65.9 million and $64.2 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.


G -- INCOME TAXES


76Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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

Income Taxes 2012 2011 2010
  (Millions of Dollars)
       
Current tax expense (benefit) $(1.4) $(108.3) $95.2
Deferred income taxes, net 195.2
 269.0
 72.9
Investment tax credit, net (1.1) (3.9) (3.3)
Total Income Tax Expense $192.7
 $156.8
 $164.8

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

  2012 2011 2010
    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 $195.6
 35.0 % $173.3
 35.0 % $167.6
 35.0 %
State income taxes net of federal tax benefit 28.8
 5.1 % 25.9
 5.2 % 24.5
 5.1 %
Production tax credits - wind (15.9) (2.8)% (8.7) (1.8)% (7.2) (1.5)%
Domestic production activities deduction (12.6) (2.3)% (12.6) (2.5)% (12.6) (2.6)%
AFUDC - Equity (12.2) (2.2)% (20.7) (4.2)% (11.3) (2.4)%
Investment tax credit restored (1.1) (0.2)% (3.9) (0.8)% (3.3) (0.7)%
Other, net 10.1
 1.8 % 3.5
 0.7 % 7.1
 1.4 %
Total Income Tax Expense $192.7
 34.4 % $156.8
 31.6 % $164.8
 34.3 %

77Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K


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

Deferred Tax Assets 2012 2011
  (Millions of Dollars)
Current    
Uncollectible account expense $17.4
 $25.5
Employee benefits and compensation 12.6
 11.9
Recoverable gas costs 0.4
 0.8
Other 22.4
 —
Total Current Deferred Tax Assets 52.8
 38.2
     
Non-current    
Deferred revenues 250.0
 279.7
Future federal tax benefits 118.1
 8.5
Employee benefits and compensation 92.3
 95.0
Construction advances 19.1
 22.9
Other 3.8
 10.6
Total Non-Current Deferred Tax Assets 483.3
 416.7
Total Deferred Tax Assets $536.1
 $454.9
Deferred Tax Liabilities 2012 2011
  (Millions of Dollars)
Current    
Prepaid items $48.7
 $49.1
Total Current Deferred Tax Liabilities 48.7
 49.1
     
Non-current    
Property-related 1,639.5
 1,373.2
Employee benefits and compensation 145.0
 135.3
Investment in transmission affiliate 125.9
 112.3
Deferred transmission costs 45.7
 47.4
Other 60.8
 32.5
Total Non-current Deferred Tax Liabilities 2,016.9
 1,700.7
Total Deferred Tax Liabilities $2,065.6
 $1,749.8
     
Consolidated Balance Sheet Presentation 2012 2011
Current Deferred Tax Asset (Liability) $4.1
 $(10.9)
Non-Current Deferred Tax Asset (Liability) $(1,533.6) $(1,284.0)

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, 2012, we had approximately $281.0 million and $19.8 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of approximately $98.3 million and $19.8 million, respectively. As of December 31, 2011, we had approximately $24.3 million of net operating loss carryforwards resulting in deferred tax assets of approximately $8.5 million. These net operating loss carryforwards begin to expire in 2030. We anticipate that we will have future taxable income sufficient to utilize these deferred tax assets.

78Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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

 2012 2011
 (Millions of Dollars)
    
Balance as of January 1$10.6
 $15.8
Additions based on tax positions related to the current year—
 —
Additions for tax positions of prior years10.8
 —
Reductions for tax positions of prior years(10.6) (3.2)
Reductions due to statute of limitations—
 —
Settlements during the period—
 (2.0)
Balance as of December 31$10.8
 $10.6

The amount of unrecognized tax benefits as of December 31, 2012 and 2011 excludes deferred tax assets related to uncertainty in income taxes of $9.8 million and $10.6 million, respectively. As of December 31, 2012 and 2011, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $0.9 million and zero, respectively.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2012, 2011 and 2010, we recognized approximately $0.2 million, $0.6 million and $3.6 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2012, 2011 and 2010, we recognized no penalties in the Consolidated Income Statements. We had approximately $0.2 million and $2.0 million of interest accrued in the Consolidated Balance Sheets as of December 31, 2012 and 2011, respectively.

Within the next twelve months, it is reasonably possible that our unrecognized tax benefits may decrease by $1.0 million as a result of further IRS guidance relating to an uncertain tax position.

Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2007 through 2012 are subject to Federal and Wisconsin examination.


H -- COMMON EQUITY

Share-Based Compensation Plans:   Our employees participate in a plan approved by Wisconsin Energy stockholders that provides a long-term incentive through equity interests in Wisconsin Energy to outside directors, selected officers and key employees of Wisconsin Energy and its subsidiaries. The plan provides for the granting of Wisconsin Energy stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in Wisconsin Energy common stock, cash or a combination thereof. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding Wisconsin Energy stock options held by our employees during the period other than necessary adjustments as a result of Wisconsin Energy's two-for-one stock split on March 1, 2011.


79Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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

  2012 2011 2010
  (Millions of Dollars)
       
Performance units $14.2

$20.3

$24.6
Stock options 2.6

2.5

7.0
Restricted stock 2.0
 1.1
 0.8
Share-based compensation expense $18.8
 $23.9
 $32.4
       
Related Tax Benefit $7.5
 $9.6
 $13.0

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

The following is a summary of Wisconsin Energy stock option activity by our employees during 2012:

      Weighted-Average  
    Weighted- Remaining Aggregate
  Number of Average Contractual Life Intrinsic Value
Stock Options Options Exercise Price (Years) (Millions)
Outstanding as of January 1, 2012 9,907,526
 $21.76
    
Granted 903,865
 $34.88
    
Exercised (2,394,515) $18.98
    
Forfeited —
 $—
    
Outstanding as of December 31, 2012 8,416,876
 $23.96
 5.3 $108.5
         
Exercisable as of December 31, 2012 6,779,306
 $22.27
 4.6 $98.8

We expect that substantially all of the outstanding options as of December 31, 2012 will be exercised.

In January 2013, the Compensation Committee awarded 1,365,970 Wisconsin Energy non-qualified stock options at an exercise price of $37.46 to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

The intrinsic value of Wisconsin Energy options exercised during the years ended December 31, 2012, 2011 and 2010 was $42.9 million, $31.8 million and $53.2 million, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $45.4 million, $49.3 million and $81.1 million during the years ended December 31, 2012, 2011 and 2010, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately zero, $9.7 million and $21.0 million, respectively.

80Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K


The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of December 31, 2012:

  Options Outstanding Options Exercisable
    Weighted-Average   Weighted-Average
      Remaining     Remaining
  Number of Exercise Contractual Number of Exercise Contractual
Range of Exercise Prices Options Price  Life (Years) Options Price  Life (Years)
$16.72  to  $19.74 1,506,079
 $18.92 2.6 1,506,079
 $18.92 2.6
$21.11  to  $24.92 5,579,532
 $23.15 5.2 5,149,522
 $23.00 5.1
$29.35  to  $34.88 1,331,265
 $33.10 8.7 123,705
 $32.77 8.6
             
  8,416,876
 $23.96 5.3 6,779,306
 $22.27 4.6

The following table summarizes information about non-vested Wisconsin Energy options held by our employees during 2012:

  Number of 
Weighted-
Average
Non-Vested Stock Options Options  Fair Value
     
Non-Vested as of January 1, 2012 2,953,580
 $3.78
Granted 903,865
 $3.34
Vested (2,219,875) $3.95
Forfeited —
 $—
Non-Vested as of December 31, 2012 1,637,570
 $3.31

As of December 31, 2012, total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $1.0 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 grants of Wisconsin Energy restricted stock to certain of our key employees. The following restricted stock activity related to our employees occurred during 2012:

  Number of 
Weighted-
Average
Market
Restricted Shares Shares Price
Outstanding as of January 1, 2012 115,946
  
Granted 71,496
 $34.46
Released (55,160) $24.19
Forfeited (5,890) $27.35
Outstanding as of December 31, 2012 126,392
  
Recipients of previously issued Wisconsin Energy restricted shares have the right to vote the shares and receive dividends, and the shares have vesting periods ranging up to 10 years.

In January 2013, the Compensation Committee awarded 53,055 restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and 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.

Wisconsin Energy records the market value of the restricted stock awards on the date of grant. We then amortize

81Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

our share of allocated expense over the vesting period of the awards. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was $2.2 million, $1.7 million and $1.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was zero, $0.6 million and $0.6 million, respectively.

As of December 31, 2012, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $2.0 million, which is expected to be recognized over the next 21 months on a weighted-average basis.

Performance Units:   In January 2012, 2011 and 2010, the Compensation Committee awarded 333,685, 413,990 and 520,620 Wisconsin Energy performance units, respectively, to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units that will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's common stock over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash. We are accruing our share of compensation costs over the three-year performance period based on our estimate of the final expected value of the awards. Performance units earned as of December 31, 2012, 2011 and 2010 had a total intrinsic value of $17.1 million, $23.8 million and $12.1 million, respectively. The awards were subsequently distributed to our officers and key employees in January 2013, 2012 and 2011. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $6.2 million, $9.6 million and $4.2 million, respectively. As of December 31, 2012, total compensation cost related to performance units not yet recognized was approximately $11.9 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

In January 2013, the Compensation Committee awarded 230,245 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Equity Contribution:   Our capitalization reflects the impact of a $100.0 million equity contribution from Wisconsin Energy during 2010.

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

We are required to maintain a capital structure that differs from GAAP as it reflects regulatory adjustments. Consistent with the 2010 rate case order, the 2013 PSCW rate case order requires us to maintain a common equity ratio range of between 48.5% and 53.5%. We are in compliance with the common equity ratio range. We must obtain PSCW approval to pay dividends above the test year levels that would cause us to fall below the authorized level of common equity.

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

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

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


82Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

I -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

Debentures and Notes:   As of December 31, 2012, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:

 (Millions of Dollars)
  
2013$300.0
2014300.0
2015250.0
2016—
2017—
Thereafter1,687.0
Total$2,537.0

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

In December 2012, we issued $250 million of 3.65% Debentures due December 15, 2042. The debentures were issued under an existing shelf registration statement filed with the SEC in February 2011. The net proceeds were used to repay short-term debt and for other general corporate purposes.

In September 2011, we issued $300 million of 2.95% Debentures due September 15, 2021. The debentures were issued under an existing shelf registration statement filed with the SEC in February 2011. The net proceeds were used to repay short-term debt and for other general corporate purposes.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147.0 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2012 and 2011, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Obligations Under Capital Leases

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

Power Purchase Commitment:   In 1997, we entered into a 25 -year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.

PWGS:   We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. The leased plants and corresponding obligations for the plants have been recorded at the estimated fair value of $681.0 million.

83Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

We are amortizing the leased plants on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $128.9 million in the year 2021 for PWGS 1 and to approximately $127.9 million in the year 2024 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for the plants was $651.9 million as of December 31, 2012 and will decrease to zero over the remaining lives of the contracts.

Oak Creek Expansion:   We are leasing OC 1, OC 2 and the common facilities, which are also utilized by our Oak Creek Units 5-8, from We Power under PSCW approved leases. We are amortizing the leased plants on a straight-line basis over the 30-year term of the leases. The common coal handling system was placed in service in November 2007 and the water intake system was placed in service in January 2009. OC 1 and the remaining common facilities were placed in service in February 2010. OC 2 was placed in service in January 2011. The leased plants and corresponding capital lease obligations have been recorded at the estimated fair value of $1,954.0 million. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. The total obligation under the capital leases was $1,988.2 million as of December 31, 2012, and will decrease to zero over the remaining life of the contracts.

We paid the following lease payments during 2012, 2011 and 2010:

  2012 2011 2010
  (Millions of Dollars)
       
Long-term power purchase commitment $32.5
 $31.3
 $30.2
PWGS  99.0
 97.5
 97.4
Oak Creek Expansion 269.3
 266.1
 178.6
Total $400.8
 $394.9
 $306.2

The following table summarizes our capitalized leased facilities as of December 31:
Capital Lease Assets 2012 2011
  (Millions of Dollars)
     
Long-term Power Purchase Commitment    
Under capital lease $140.3
 $140.3
Accumulated amortization (86.8) (81.1)
Total Long-term Power Purchase Commitment $53.5
 $59.2
     
PWGS     
Under capital lease $681.0
 $670.9
Accumulated amortization (162.6) (135.1)
Total PWGS  $518.4
 $535.8
     
Oak Creek Expansion    
Under capital lease $1,954.0
 $1,954.0
Accumulated amortization (185.7) (120.8)
Total Oak Creek $1,768.3
 $1,833.2
     
Total Leased Facilities $2,340.2
 $2,428.2

84Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2012 are as follows:

  Power      
  Purchase   Oak Creek  
Capital Lease Obligations Commitment PWGS Expansion Total
  (Millions of Dollars)
         
2013 $40.4
 $99.0
 $269.4
 $408.8
2014 41.9
 99.0
 269.4
 410.3
2015 43.5
 99.0
 288.2
 430.7
2016 45.1
 99.0
 299.8
 443.9
2017 13.9
 99.0
 299.8
 412.7
Thereafter 71.5
 1,380.8
 6,720.4
 8,172.7
Total Minimum Lease Payments 256.3
 1,875.8
 8,147.0
 10,279.1
Less:  Estimated Executory Costs (68.4) —
 —
 (68.4)
Net Minimum Lease Payments 187.9
 1,875.8
 8,147.0
 10,210.7
Less:  Interest (67.9) (1,223.9) (6,158.8) (7,450.6)
Present Value of Net        
Minimum Lease Payments 120.0
 651.9
 1,988.2
 2,760.1
Less:  Due Currently (15.8) (7.7) (33.5) (57.0)
Total Capital Lease Obligations $104.2
 $644.2
 $1,954.7
 $2,703.1


J -- SHORT-TERM DEBT

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

  2012 2011
    Interest   Interest
  Balance Rate Balance Rate
  (Millions of Dollars, except for percentages)
         
Commercial paper $105.5 0.27% $352.0 0.24%

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

  2012 2011
  (Millions of Dollars, except for percentages)
     
Maximum Commercial Paper Outstanding $382.0
 $370.5
Average Commercial Paper Outstanding $251.6
 $217.4
Weighted-Average Interest Rate 0.26% 0.21%

In December 2012, we entered into a new bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 65%.

As of December 31, 2012, we had approximately $494.1 million of available, undrawn lines under our bank back-up credit facility and approximately $105.5 million of commercial paper outstanding that was supported by the available lines of credit. Our bank back-up credit facility expires in December 2017. As of December 31, 2012, our subsidiary had a $23.4 million note payable to Wisconsin Energy with a weighted-average interest rate of 6.25%.

Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell

85Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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.

As of December 31, 2012, we were in compliance with all financial covenants.


K -- DERIVATIVE INSTRUMENTS

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

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. We do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of December 31, 2012, we recognized $3.7 million in regulatory assets and $16.7 million in regulatory liabilities related to derivatives in comparison to $14.1 million in regulatory assets and $20.3 million in regulatory liabilities as of December 31, 2011.

We record our current derivative assets on the balance sheet in other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $0.6 million is recorded in other deferred charges and other assets, and we had no long-term portion of derivative liabilities. Our Consolidated Balance Sheets as of December 31, 2012 and 2011 include:

  December 31, 2012 December 31, 2011
  
Derivative
Asset
 
Derivative
Liability
 
Derivative
Asset
 
Derivative
Liability
  (Millions of Dollars)
Natural Gas $0.6
 $0.5
 $0.7
 $4.6
Fuel Oil 0.4
 —
 0.3
 0.1
FTRs 4.7
 —
 5.7
 —
Coal 11.1
 —
 12.5
 —
Total $16.8
 $0.5
 $19.2
 $4.7


86Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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, 2012 and 2011 were as follows:

  2012 2011
  Volume Gains (Losses) Volume Gains (Losses)
    (Millions of Dollars)   (Millions of Dollars)
Natural Gas 38.9 million Dth $(16.4) 32.2 million Dth $(15.5)
Fuel Oil 7.0 million gallons 1.8
 13.0 million gallons 6.9
FTRs 20,616 MW 6.1
 23,718 MW 12.5
Total   $(8.5)   $3.9

As of December 31, 2012 and 2011, we posted collateral of $2.1 million and $6.4 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.


L -- 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.


87Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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

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 0.6
 11.5
 4.7
 16.8
Total $3.3
 $11.5
 $4.7
 $19.5
Liabilities:        
Derivatives $0.5
 $—
 $—
 $0.5
Total $0.5
 $—
 $—
 $0.5

Recurring Fair Value Measures As of December 31, 2011
  Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
Assets:        
Restricted Cash $45.5
 $—
 $—
 $45.5
Derivatives 0.3
 13.2
 5.7
 19.2
Total $45.8
 $13.2
 $5.7
 $64.7
Liabilities:        
Derivatives $4.3
 $0.4
 $—
 $4.7
Total $4.3
 $0.4
 $—
 $4.7

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 is being 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.


88Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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

  2012 2011
  (Millions of Dollars)
     
Balance as of January 1 $5.7
 $5.9
Realized and unrealized gains (losses) —
 —
Purchases 11.0
 16.1
Issuances —
 —
Settlements (12.0) (16.3)
Transfers in and/or out of Level 3 —
 —
Balance as of December 31 $4.7
 $5.7
     
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 K -- 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:

  2012 2011
  Carrying Fair Carrying Fair
Financial Instruments Amount Value Amount Value
  (Millions of Dollars)
         
Preferred stock, no redemption required $30.4
 $26.0
 $30.4
 $25.1
Long-term debt including current portion $2,537.0
 $2,900.8
 $2,287.0
 $2,669.0

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.


M -- BENEFITS

Pensions and Other Post-retirement Benefits:   We participate in Wisconsin Energy's defined benefit pension plans that cover substantially all of our employees. Generally, employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Approximately half of our projected benefit obligation relates to benefits based upon years of service and final average salary.

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

The assets, obligations and the components of our pension costs are allocated by Wisconsin Energy's actuary to

89Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

each of the participating companies as if each participating company had its own plan. The disclosures below are based on an allocation to us of the amounts for Wisconsin Energy's pension plans.

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

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

  Pension OPEB
  2012 2011 2012 2011
  (Millions of Dollars)
Change in Benefit Obligation        
Benefit Obligation at January 1 $1,153.3
 $1,056.0
 $317.3
 $297.1
Service cost 19.8
 14.5
 9.8
 9.9
Interest cost 56.8
 58.4
 16.7
 17.0
Participants' contributions —
 —
 9.1
 10.8
Inter Plan transfer (0.1) 1.9
 —
 —
Actuarial loss (gain) 144.3
 84.2
 (26.9) 6.5
Other accrued benefits 30.3
 —
 —
 —
Gross benefits paid (94.1) (61.7) (21.4) (24.7)
Federal subsidy on benefits paid N/A
 N/A
 0.8
 0.7
Benefit Obligation at December 31 $1,310.3
 $1,153.3
 $305.4
 $317.3
         
Change in Plan Assets        
Fair Value at January 1 $1,018.1
 $813.7
 $173.9
 $135.9
Actual earnings on plan assets 102.6
 26.8
 19.6
 6.3
Employer contributions 94.5
 239.3
 13.6
 45.6
Participants' contributions —
 —
 9.1
 10.8
Gross benefits paid (94.1) (61.7) (21.4) (24.7)
Fair Value at December 31 $1,121.1
 $1,018.1
 $194.8
 $173.9
         
Net Liability $189.2
 $135.2
 $110.6
 $143.4

As of December 31, 2012, our qualified and non-qualified pension plans were under-funded by $98.5 million and $90.7 million, respectively. As of December 31, 2011, our qualified and non-qualified pension plans were under-funded by $53.0 million and $82.2 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
  2012 2011 2012 2011
  (Millions of Dollars)
         
Other deferred charges $—
 $—
 $0.3
 $0.2
Other long-term liabilities 189.2
 135.2
 110.9
 143.6
Net liability $189.2
 $135.2
 $110.6
 $143.4

The accumulated benefit obligation for all defined benefit plans was $1,309.0 million and $1,152.2 million as of December 31, 2012 and 2011, respectively.


90Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

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

  Pension OPEB
  2012 2011 2012 2011
  (Millions of Dollars)
         
Net actuarial loss $543.6
 $462.5
 $32.7
 $73.1
Prior service costs (credits) 11.4
 13.5
 (3.5) (5.4)
Transition obligation —
 —
 —
 0.3
Total $555.0
 $476.0
 $29.2
 $68.0

We estimate that 2013 periodic pension costs will include the amortization of previously unrecognized benefit costs referred to above of $43.4 million and OPEB credits of $0.5 million.

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

  Pension OPEB
  2012 2011 2010 2012 2011 2010
  (Millions of Dollars)
Net Periodic Benefit Cost            
Service cost $19.8
 $14.5
 $22.1
 $9.8
 $9.9
 $10.6
Interest cost 56.8
 58.4
 59.0
 16.7
 17.0
 17.4
Expected return on plan assets (71.8) (63.8) (59.5) (13.0) (11.2) (9.1)
Amortization of:            
Transition obligation —
 —
 —
 0.3
 0.3
 0.3
Prior service cost (credit) 2.1
 2.1
 2.1
 (1.9) (1.9) (11.9)
Actuarial loss 30.6
 24.3
 18.8
 5.0
 4.2
 8.2
Other 0.4
 —
 —
 —
 —
 —
Net Periodic Benefit Cost $37.9
 $35.5
 $42.5
 $16.9
 $18.3
 $15.5

In addition to the costs above, in 2011 we recorded net pension costs of less than $13 million relating to the settlement of pension litigation. See Note P --Commitments and Contingencies in this report.
The charges were after considering insurance and reserves established in 2010.

  Pension OPEB
  2012 2011 2010 2012 2011 2010
Weighted-Average assumptions used to            
determine benefit obligations as of Dec. 31            
Discount rate 4.10% 5.05% 5.60% 4.15% 5.20% 5.70%
Rate of compensation increase 4.00% 4.00% 4.00% N/A N/A N/A
             
Weighted-Average assumptions used to            
determine net cost for year ended Dec. 31            
Discount rate 5.05% 5.60% 6.05% 5.20% 5.70% 5.75%
Expected return on plan assets 7.25% 7.25% 7.25% 7.50% 7.50% 7.50%
Rate of compensation increase 4.00% 4.00% 4.00% N/A N/A N/A
             
Assumed health care cost trend rates as of Dec. 31          
Health care cost trend rate assumed for next year (Pre 65 / Post 65)   7.5%/7.5% 8.0%/12.0% 7.5%/16.0%
Rate that the cost trend rate gradually adjusts to   5.00% 5.00% 5.00%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65) 2017/2017 2017/2017 2015/2016

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in

91Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

2012, 2011 and 2010. Wisconsin Energy consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.

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 $26.7
 $(22.4)
Total of service and interest cost components $3.9
 $(3.2)

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 share of plan assets by asset category within the fair value hierarchy (for further level information, see Note L):

  As of December 31, 2012
Asset Category - Pension Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $11.1
 $—
 $—
 $11.1
Equities:        
U.S. Equity 377.3
 —
 —
 377.3
International Equity 109.0
 24.6
 —
 133.6
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 54.8
 442.3
 —
 497.1
International Bonds 65.3
 36.7
 —
 102.0
Total $617.5
 $503.6
 $—
 $1,121.1

92Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

  As of December 31, 2011
Asset Category - Pension Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $6.9
 $—
 $—
 $6.9
Equities:        
U.S. Equity 367.0
 —
 —
 367.0
International Equity 81.0
 27.3
 —
 108.3
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 61.9
 405.5
 —
 467.4
International Bonds 33.0
 35.5
 —
 68.5
Total $549.8
 $468.3
 —
 $1,018.1

(a)This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.
The following table summarizes the fair value of our share of OPEB plan assets by asset category within the fair value hierarchy:

  As of December 31, 2012
Asset Category - OPEB Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $1.2
 $—
 $—
 $1.2
Equities:        
U.S. Equity 86.0
 —
 —
 86.0
International Equity 27.2
 1.5
 —
 28.7
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 3.4
 61.3
 —
 64.7
International Bonds 10.5
 3.7
 —
 14.2
Total $128.3
 $66.5
 —
 $194.8

  As of December 31, 2011
Asset Category - OPEB Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $1.6
 —
 —
 $1.6
Equities:        
U.S. Equity 77.3
 —
 —
 77.3
International Equity 21.9
 1.6
 —
 23.5
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 5.6
 56.5
 —
 62.1
International Bonds 5.9
 3.5
 —
 9.4
Total $112.3
 $61.6
 —
 $173.9

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


93Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

Cash Flows:

  Pension  
Employer Contributions Qualified Non-Qualified OPEB
  (Millions of Dollars)
       
2010 $—
 $5.6
 $2.7
2011 $234.1
 $5.2
 $45.6
2012 $88.5
 $6.0
 $13.6

The following table identifies our expected benefit payments over the next 10 years:

     
     
Year Pension Gross OPEB
  (Millions of Dollars)
     
2013 $89.2
 $13.1
2014 $87.6
 $13.8
2015 $86.4
 $14.7
2016 $86.5
 $15.5
2017 $86.9
 $16.4
2018-2022 $423.3
 $89.9

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 $12.5 million, $12.9 million and $12.5 million during 2012, 2011 and 2010, respectively.

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


N -- SEGMENT REPORTING

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

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


94Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

Summarized financial information concerning our reportable segments for the years ended December 31, 2012, 2011 and 2010 is shown in the following table:

  Reportable Segments    
Year Ended Electric Gas Steam Other (a) Total
  (Millions of Dollars)
December 31, 2012          
Operating Revenues (b) $3,193.9
 $385.1
 $34.3
 $—
 $3,613.3
Depreciation and Amortization $230.3
 $23.9
 $3.4
 $—
 $257.6
Operating Income (Loss) (c) $536.5
 $50.0
 $(3.2) $—
 $583.3
Equity in Earnings          
of Transmission Affiliate $57.6
 $—
 $—
 $—
 $57.6
Capital Expenditures $524.9
 $50.8
 $—
 $0.1
 $575.8
Total Assets (d) $11,209.4
 $641.7
 $66.3
 $105.2
 $12,022.6
           
December 31, 2011          
Operating Revenues (b) $3,211.3
 $477.3
 $39.0
 $—
 $3,727.6
Depreciation and Amortization $190.2
 $26.8
 $3.3
 $—
 $220.3
Operating Income (c) $425.6
 $46.7
 $1.3
 $—
 $473.6
Equity in Earnings          
of Transmission Affiliate $54.9
 $—
 $—
 $—
 $54.9
Capital Expenditures $665.0
 $39.0
 $2.6
 $—
 $706.6
Total Assets (d) $10,816.1
 $654.9
 $67.8
 $122.5
 $11,661.3
           
December 31, 2010          
Operating Revenues (b) $2,936.3
 $481.6
 $38.8
 $—
 $3,456.7
Depreciation and Amortization $187.0
 $25.9
 $3.3
 $—
 $216.2
Operating Income (c) $448.1
 $38.9
 $2.2
 $—
 $489.2
Equity in Earnings          
of Transmission Affiliate $52.7
 $—
 $—
 $—
 $52.7
Capital Expenditures $574.9
 $38.8
 $2.5
 $1.1
 $617.3
Total Assets (d) $9,356.8
 $638.1
 $65.3
 $110.5
 $10,170.7

(a)Other includes primarily non-utility property and investments, materials and supplies, deferred charges and other corporate items.

(b)We account for intersegment revenues at a tariff rate established by the PSCW. Intersegment revenues were not material.

(c)We evaluate operating income to manage our utility business. Equity in Earnings of Transmission Affiliate, Interest Expense and Income Taxes are not included in segment operating income.

(d)Common utility plant is allocated to electric, gas and steam utility operations to determine segment assets.


O -- RELATED PARTIES

We provide to and receive from certain of our Wisconsin Energy affiliates managerial, financial, accounting, legal, data processing and other services in accordance with service agreements approved by the PSCW. In addition, we make lease payments to We Power for PWGS 1, PWGS 2, OC 1 and OC 2. We also receive and/or provide certain services to other associated companies in which we have, or Wisconsin Energy has, an equity investment.

American Transmission Company LLC:   As of December 31, 2012, we have a 23.0% interest in ATC. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which are 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 new generating units constructed as part of Wisconsin Energy's PTF strategy. ATC reimburses us for these costs when new generation is placed in service. As of December 31, 2012 and 2011, we

95Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

had a receivable of zero and $5.4 million, respectively, for these items. During the years ended December 31, 2012, 2011 and 2010, our equity in earnings from ATC was $57.6 million, $54.9 million and $52.7 million, respectively. During the years ended December 31, 2012, 2011 and 2010, distributions received from ATC were $46.1 million, $43.7 million and $43.3 million, respectively.

Summary financial information as of December 31 from the financial statements of ATC is as follows:

  2012 2011 2010
  (Millions of Dollars)
       
Operating Revenues $603.3
 $567.2
 $556.7
Operating Income $322.2
 $305.6
 $305.6
Net Income $237.4
 $223.9
 $219.7
       
Current Assets $63.1
 $58.7
 $59.9
Non-Current Assets $3,274.7
 $3,053.7
 $2,888.4
Current Liabilities $251.5
 $298.5
 $428.4
Non-Current Liabilities $1,645.8
 $1,482.7
 $1,260.0

We provided and received services from the following associated companies during 2012, 2011 and 2010:

Company 2012 2011 2010
  (Millions of Dollars)
Affiliate      
       
Net Services Provided      
We Power (excluding lease payments) $2.1
 $5.3
 $0.6
Wisconsin Gas $62.1
 $67.4
 $64.8
Other $1.2
 $1.1
 $0.9
       
Net Services Received      
We Power (lease payments) $375.1
 $370.5
 $367.8
Wisconsin Energy $18.3
 $23.7
 $26.5
       
Equity Investee - ATC      
       
Services Provided $8.2
 $10.8
 $16.9
       
Services Received $222.7
 $219.2
 $220.8


96Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

As of December 31, 2012 and 2011, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:

Equity Investee - ATC 2012 2011
  (Millions of Dollars)
Services Provided $0.5
 $0.7
     
     
Services Received $18.6
 $18.1


P -- COMMITMENTS AND CONTINGENCIES

Capital Expenditures:   We have made certain commitments in connection with 2013 capital expenditures. During 2013, we estimate that total capital expenditures will be approximately $521.6 million.

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)
  
2013$6.5
20143.9
20153.9
20163.7
20173.2
Thereafter25.9
Total$47.1

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 our manufactured gas plant sites and related disposal sites, as well as our coal combustion product disposal/landfill sites, 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 we or a predecessor company historically owned or operated a manufactured gas plant. These sites have been substantially remediated or are at various stages of investigation, monitoring and remediation. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon on-going analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $6 million to $18 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, 2012 and 2011, we established reserves of $7.2 million and $6.4 million, respectively, related to future remediation costs.

97Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K


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

Coal Combustion Product Landfill Sites:   We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required various levels of monitoring or remediation. Where we have become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. During 2012, 2011 and 2010, we incurred $0.3 million, $0.2 million and $0.4 million, respectively, in landfill remediation expenses. As of December 31, 2012, we have no reserves established related to coal combustion product landfill sites.

EPA - Consent Decree:   In April 2003, we reached a Consent Decree with the EPA in which we agreed to significantly reduce air emissions from our coal-fired generating facilities. In July 2003, the Consent Decree was amended to include the state of Michigan, and in October 2007, the U.S. District Court for the Eastern District of Wisconsin approved and entered the amended Consent Decree. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS that began service in 2012. In order to achieve the reductions agreed to in the Consent Decree, over the past almost 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 estimate we will spend an additional $22 million in 2013 for final implementation costs.

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 $60 million and $65 million subject to PSCW approval, and receiving a construction permit from the WDNR. We expect to file for a Certificate of Authority from the PSCW and an air permit from the WDNR during the second quarter of 2013.

We have made significant progress on the four voluntary goals that we submitted in a December 2011 letter to the EPA: (1) we achieved the reductions in annual SO2 emissions from the plant to no more than 4,500 tons (a 65% decrease from 2001 emission levels); (2) the planned conversion of the plant from coal to natural gas eliminates the requirement to meet the MATS rules and, therefore, the need for a dry sorbent injection system; (3) we held open houses and tours of VAPP to help inform the community on the plant, the unique role that it plays in the community, and to share environmental successes and future plans; and (4) we announced plans for converting VAPP to natural gas fuel by 2015-2016, provided that we can obtain authorization from the PSCW to do so.

Cash Balance Pension Plan:   In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. The complaint alleged that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of ERISA and were owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. In September 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant.
In November 2011, the Plan entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, the Plan

98Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2012 Form 10-K

agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $13 million for 2011 after considering insurance and reserves established in 2010. The court approved the settlement and issued its written order in April 2012. Substantially all payments to class members have been made pursuant to the settlement. We do not anticipate further charges as a result of the settlement.

Q -- SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2012, we paid $109.0 million in interest, net of amounts capitalized, and received $91.2 million in net refunds from income taxes. During the year ended December 31, 2011, we paid $89.5 million in interest, net of amounts capitalized, and $1.1 million in income taxes, net of refunds. During the year ended December 31, 2010, we paid $99.7 million in interest, net of amounts capitalized, and $112.0 million in income taxes, net of refunds.

As of December 31, 2012, 2011 and 2010, the amount of accounts payable related to capital expenditures was $15.7 million, $16.7 million and $16.8 million, respectively.

99Wisconsin Electric Power Company
2012 Form 10-K

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Electric Power Company:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary (the "Company") as of December 31, 20122015 and 2011,2014, and the related consolidated income statements, statements of income, common equity, and statements of cash flows for each of the three years in the period ended December 31, 2012.2015. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2).15. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary as of December 31, 20122015 and 2011,2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012,2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin
February 27,26, 2016


2015 Form 10-K49Wisconsin Electric Power Company
Table of Contents

B. CONSOLIDATED INCOME STATEMENTS

Year Ended December 31      
(in millions) 2015 2014 2013
Operating revenues $3,854.1
 $4,059.4
 $3,800.2
       
Operating expenses      
Cost of sales 1,399.0
 1,660.7
 1,436.4
Other operation and maintenance 1,384.9
 1,356.4
 1,417.3
Depreciation and amortization 304.0
 278.3
 230.6
Property and revenue taxes 117.3
 113.6
 110.0
Total operating expenses 3,205.2
 3,409.0
 3,194.3
       
Operating income 648.9
 650.4
 605.9
       
Equity in earnings of transmission affiliate 47.8
 57.9
 60.2
Other income, net 11.2
 8.7
 17.4
Interest expense 119.0
 116.5
 121.4
Other expense (60.0) (49.9) (43.8)
       
Income before income taxes 588.9
 600.5
 562.1
Income tax expense 212.0
 222.6
 200.9
Net income 376.9
 377.9
 361.2
       
Preferred stock dividend requirements 1.2
 1.2
 1.2
Net income attributed to common shareholder $375.7
 $376.7
 $360.0

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


2015 Form 10-K50Wisconsin Electric Power Company
Table of Contents

C. CONSOLIDATED BALANCE SHEETS
At December 31    
(in millions, except share and per share amounts) 2015 2014
Assets    
Property, plant, and equipment    
In service $10,917.1
 $10,544.4
Accumulated depreciation (3,461.9) (3,406.1)
  7,455.2
 7,138.3
Construction work in progress 170.6
 140.9
Leased facilities, net 2,141.7
 2,215.0
Net property, plant, and equipment 9,767.5
 9,494.2
Investments    
Equity investment in transmission affiliate 382.2
 372.9
Other 0.3
 0.2
Total investments 382.5
 373.1
Current assets    
Cash and cash equivalents 27.1
 24.0
Accounts receivable and unbilled revenues, net of reserves of $43.0 and $46.8, respectively 461.4
 488.4
Accounts receivable from related parties 41.1
 8.1
Materials, supplies, and inventories 301.6
 320.5
Prepayments 171.8
 139.5
Other 19.6
 19.0
Total current assets 1,022.6
 999.5
Deferred charges and other assets    
Regulatory assets 1,855.9
 1,626.9
Other 111.1
 103.5
Total deferred charges and other assets 1,967.0
 1,730.4
Total assets $13,139.6
 $12,597.2
     
Capitalization and liabilities    
Capitalization    
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding $332.9
 $332.9
Additional paid in capital 999.7
 984.4
Retained earnings 2,231.4
 2,095.5
Preferred stock 30.4
 30.4
Long-term debt 2,658.8
 2,162.7
Capital lease obligations 2,692.5
 2,712.5
Total capitalization 8,945.7
 8,318.4
Current liabilities    
Current portion of long-term debt and capital lease obligations 123.6
 355.6
Short-term debt 144.0
 306.8
Subsidiary note payable to WEC Energy Group 19.6
 22.4
Accounts payable 286.4
 287.2
Accounts payable to related parties 95.7
 87.8
Accrued payroll and benefits 87.5
 87.1
Other 115.7
 113.7
Total current liabilities 872.5
 1,260.6
Deferred credits and other liabilities    
Regulatory liabilities 741.2
 615.9
Deferred income taxes 2,110.0
 1,917.2
Pension and other postretirement benefit obligations 210.9
 254.5
Other 259.3
 230.6
Total deferred credits and other liabilities 3,321.4
 3,018.2
     
Commitments and contingencies (Note 15) 
 
     
Total capitalization and liabilities $13,139.6
 $12,597.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

2015 Form 10-K51Wisconsin Electric Power Company
Table of Contents

D. CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31      
(in millions) 2015 2014 2013
Operating activities      
Net income $376.9
 $377.9
 $361.2
Reconciliation to cash provided by operating activities      
Depreciation and amortization 323.7
 302.6
 285.2
Deferred income taxes and investment tax credits, net 178.9
 191.4
 193.6
Contributions to pension and OPEB plans (107.6) (10.4) (17.6)
Change in –      
Accounts receivable and unbilled revenues (2.9) 91.0
 (137.0)
Materials, supplies, and inventories 18.8
 (39.5) 31.2
Other current assets (2.5) (8.7) 0.7
Accounts payable (5.9) 18.2
 (29.4)
Accrued taxes, net (42.1) (7.5) 23.6
Other current liabilities (1.2) (36.8) 13.1
Other, net (61.7) (15.4) 138.0
Net cash provided by operating activities 674.4
 862.8
 862.6
       
Investing activities      
Capital expenditures (519.2) (561.8) (538.9)
Investment in transmission affiliate (4.6) (11.5) (9.2)
Other, net 3.6
 5.8
 (12.0)
Net cash used in investing activities (520.2) (567.5) (560.1)
       
Financing activities      
Dividends paid on common stock (240.0) (390.0) (340.0)
Dividends paid on preferred stock (1.2) (1.2) (1.2)
Issuance of long-term debt 500.0
 250.0
 250.0
Retirement of long-term debt (250.0) (300.0) (300.0)
Change in total short-term debt (162.8) 131.9
 68.4
Other, net 2.9
 12.9
 11.3
Net cash used in financing activities (151.1) (296.4) (311.5)
       
Net change in cash and cash equivalents 3.1
 (1.1) (9.0)
Cash and cash equivalents at beginning of year 24.0
 25.1
 34.1
Cash and cash equivalents at end of year $27.1
 $24.0
 $25.1

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


2015 Form 10-K52Wisconsin Electric Power Company
Table of Contents

E. CONSOLIDATED STATEMENTS OF EQUITY

  Wisconsin Electric Power Company Common Shareholders' Equity    
  Common Stock Additional Paid-In Capital Retained Earnings Total Common Shareholders' Equity Preferred Stock Total Equity
(in millions)      
Balance at December 31, 2012 $332.9
 $944.7
 $2,088.8
 $3,366.4
 $30.4
 $3,396.8
Net income —
 —
 361.2
 361.2
 —
 361.2
Dividends            
Common stock —
 —
 (340.0) (340.0) —
 (340.0)
Preferred stock —
 —
 (1.2) (1.2) —
 (1.2)
Stock-based compensation —
 3.7
 —
 3.7
 —
 3.7
Tax benefit of exercised stock options allocated from parent —
 16.7
 —
 16.7
 —
 16.7
Balance at December 31, 2013 332.9
 965.1
 2,108.8
 3,406.8
 30.4
 3,437.2
Net income —
 —
 377.9
 377.9
 —
 377.9
Dividends            
Common stock —
 —
 (390.0) (390.0) —
 (390.0)
Preferred stock —
 —
 (1.2) (1.2) —
 (1.2)
Stock-based compensation —
 3.5
 —
 3.5
 —
 3.5
Tax benefit of exercised stock options allocated from parent —
 15.8
 —
 15.8
 —
 15.8
Balance at December 31, 2014 332.9
 984.4
 2,095.5
 3,412.8
 30.4
 3,443.2
Net income —
 —
 376.9
 376.9
 —
 376.9
Dividends       
    
Common stock —
 —
 (240.0) (240.0) —
 (240.0)
Preferred stock —
 —
 (1.2) (1.2) —
 (1.2)
Stock-based compensation —
 3.2
 —
 3.2
 —
 3.2
Tax benefit of exercised stock options allocated from parent —
 12.1
 —
 12.1
 —
 12.1
Other —
 —
 0.2
 0.2
 —
 0.2
Balance at December 31, 2015 $332.9
 $999.7
 $2,231.4
 $3,564.0
 $30.4
 $3,594.4

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


2015 Form 10-K53Wisconsin Electric Power Company
Table of Contents

F. CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31
(in millions, except share and per share amounts)
     2015 2014
Common equity (See Consolidated Statements of Equity)    
Common stock – $10 par value; authorized    
65,000,000 shares; outstanding – 33,289,327 shares $332.9
 $332.9
Additional paid in capital 999.7
 984.4
Retained earnings     2,231.4
 2,095.5
Total common equity 3,564.0
 3,412.8
         
Preferred stock 30.4
 30.4
         
Long-term debt Interest Rate Year Due    
Debentures (unsecured) 6.25% 2015 —
 250.0
  1.70% 2018 250.0
 250.0
  4.25% 2019 250.0
 250.0
  2.95% 2021 300.0
 300.0
  3.10% 2025 250.0
 —
  6.50% 2028 150.0
 150.0
  5.625% 2033 335.0
 335.0
  5.70% 2036 300.0
 300.0
  3.65% 2042 250.0
 250.0
  4.25% 2044 250.0
 250.0
  4.30% 2045 250.0
 —
  6.875% 2095 100.0
 100.0
         
Note (secured, nonrecourse) 4.81% 2030 2.0
 2.0
         
Obligations under capital leases     2,816.1
 2,818.1
Total long-term debt and capital lease obligations     5,503.1
 5,255.1
Unamortized debt issuance costs     (3.9) (2.8)
Unamortized discount, net     (24.3) (21.5)
Total     5,474.9
 5,230.8
Current portion of long-term debt and capital lease obligations     (123.6) (355.6)
Total long-term debt and capital lease obligations     5,351.3
 4,875.2
Total long-term capitalization     $8,945.7
 $8,318.4

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


2015 Form 10-K54Wisconsin Electric Power Company
Table of Contents

G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) General Information—On June 29, 2015, our parent company, Wisconsin Energy Corporation, acquired Integrys and changed its name to WEC Energy Group, Inc. See Note 2, Acquisition, for more information on this acquisition.

We are an electric, natural gas, and steam utility company that services electric customers in Wisconsin and Michigan's Upper Peninsula, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin.

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted.

At December 31, 2015, we had one wholly owned subsidiary, Bostco. Bostco had total assets of $29.8 million and $28.4 million as of December 31, 2015 and 2014, respectively. The financial statements include our accounts and the accounts of our wholly owned subsidiary. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(b) Reclassifications—On the income statements for the years ended December 31, 2014 and 2013, we reclassified $17.4 million and $48.0 million, respectively, from treasury grant to depreciation and amortization. This reclassification was made to be consistent with the current year presentation on the income statements.

During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $2.8 million, previously reported as other long-term assets, were reclassified to offset long-term debt on the December 31, 2014 balance sheet. We also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes, during the fourth quarter of 2015. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $46.7 million, previously reported as a separate component of current assets, to offset long-term deferred income tax liabilities on the December 31, 2014 balance sheet.

On the statements of cash flows for the years ended December 31, 2014 and 2013, we reclassified $0.8 million and $3.1 million, respectively, from depreciation and amortization to other operating activities. In addition, we reclassified $10.4 million and $17.6 million of nonqualified pension and OPEB contributions from other operating activities to contributions to pension and OPEB plans on the statements of cash flows for the years ended December 31, 2014 and 2013, respectively. These reclassifications were made to be consistent with the current year presentation on the statements of cash flows.

(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.

(d) Revenues and Customer Receivables—We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers.

We present revenues net of pass-through taxes on the income statements.

Below is a summary of the significant mechanisms we had in place that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts:

Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations.

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 set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of

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actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater return on common equity than authorized by the PSCW.

We received payments from MISO under an SSR agreement for our PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 19, Regulatory Environment, and Note 20, Michigan Settlement, for more information.

Our natural gas utility rates included a one-for-one recovery mechanism for natural gas commodity costs. We defer any difference between actual natural gas costs incurred 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.

Our residential rates included a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

Revenues are also impacted by other accounting policies related to our participation in the MISO Energy Markets. We sell and purchase power in the MISO Energy Markets, which 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. If we were a net seller in a particular hour, the net amount was reported as operating revenue. If we were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements.

We provide regulated electric, natural gas, and steam service to customers in Wisconsin and Michigan's Upper Peninsula. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2015. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2015.
(e) Materials, Supplies, and Inventories—Our inventory as of December 31 consisted of:
(in millions) 2015 2014
Materials and supplies $151.1
 $145.0
Fossil fuel 110.5
 125.5
Natural gas in storage 40.0
 50.0
Total $301.6
 $320.5

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

(f) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues 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 or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 6, Regulatory Assets and Liabilities, for more information.

(g) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, 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.


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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 3.01%, 2.93%, and 2.90% in 2015, 2014, and 2013, respectively.

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

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

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.45% for 2015 and 9.09% for 2014 and 2013, respectively. Our average AFUDC wholesale rates were 1.72%, 0.87%, and 5.89% for 2015, 2014, and 2013, respectively.

We recorded the following AFUDC for the years ended December 31:
(in millions) 2015 2014 2013
AFUDC – Debt $2.2
 $1.8
 $7.4
AFUDC – Equity $5.7
 $4.4
 $17.6

(i) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. A liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The AROs are accreted to their present value each period using the credit-adjusted risk-free interest rate associated with the expected settlement dates of the AROs. This rate is determined when the obligation is incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 8, Asset Retirement Obligations, for more information.

(j) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 15, Commitments and Contingencies, for more information.

We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state's Commission's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(k) 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

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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 are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 13, Income Taxes, for more information.

We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements.

(l) Employee Benefits—The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 14, Employee Benefits, for more information.

(m) Stock-Based Compensation—Our employees participate in the WEC Energy Group stock-based compensation plans. We record costs allocated to us related to awards held by our employees.

In accordance with stockholder approved plans, WEC Energy Group provides a long-term incentive through its equity interests to its outside directors, selected officers, and other key employees. The plans provide for the granting of stock options, restricted stock awards, performance shares, and other share-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. We recognize share-based compensation expense on a straight-line basis. Accordingly, for employee awards classified as equity awards, share-based compensation expense is measured based on the grant-date fair value of the award and is recognized as expense ratably over the requisite service period.

Stock Options

Our employees are granted WEC Energy Group non-qualified stock options that vest on a cliff-basis after a three-year period. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant. There were no modifications to the terms of outstanding stock options during the year.

The fair value of each WEC Energy Group stock option was calculated using a binomial option-pricing model. The following table shows the estimated fair value per stock option granted along with the weighted-average assumptions used in the valuation models:
  2015 2014 2013
Non-qualified stock options granted 495,550
 864,860
 1,365,970
       
Estimated fair value per non-qualified stock option $5.29
 $4.18
 $3.45
       
Risk-free interest rate 0.1% – 2.1%
 0.1% – 3.0%
 0.1% – 1.9%
Dividend yield 3.7% 3.8% 3.7%
Expected volatility 18.0% 18.0% 18.0%
Expected life (years) 5.8
 5.8
 5.9
Expected forfeiture rate 2.0% 2.0% 2.0%

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

Restricted Shares

WEC Energy Group restricted shares 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 WEC Energy Group shareholders.

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Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total stockholder return (stock price appreciation plus dividends) as compared to the total stockholder return of a peer group of companies 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 and are accounted for as liability awards accordingly. We accrue compensation costs over the three-year performance period based on our estimate of the final expected value of the awards.

See Note 9, Common Equity, for more information on WEC Energy Group's share-based compensation plans.

(n) Fair Value Measurements—Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are 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.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs.

We recognize transfers between the levels of the fair value hierarchy as of the end of the reporting period.

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based upon the quoted market value for the same issue, or by using a perpetual dividend discount model. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases, is estimated based upon the 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.

We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.

See Note 16, Fair Value Measurements, for more information.

(o) Derivative Instruments—We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by the PSCW.

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We record derivative instruments on our balance sheets as an asset or liability measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. 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 fair value accounting to be offset to regulatory assets and liabilities.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Gains and losses on derivative instruments are primarily recorded in cost of sales on our income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 17, Derivative Instruments, for more information.

(p) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.
NOTE 2—ACQUISITION

On June 29, 2015, our parent company acquired 100% of the outstanding common shares of Integrys, a provider of regulated natural gas and electricity, as well as nonregulated renewable energy and compressed natural gas products and services. The combined company was renamed WEC Energy Group, Inc. Our parent company now owns approximately 60% of ATC, a for-profit transmission company regulated by the FERC. Our ownership interest in ATC did not change as a result of the acquisition.

The acquisition was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order includes the following conditions:

We will be subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanism, if we earn over our authorized rate of return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and will reduce our transmission escrow. All utility earnings above the first 50 basis points will be solely used to reduce the transmission escrow.

Any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and Wisconsin Public Service Corporation filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that no new generation is currently needed.

We do not believe that the conditions set forth in the various regulatory orders approving the acquisition will have a material impact on our operations or financial results.


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In 2015, we recorded $6.6 million of severance expense that resulted from employee reductions related to the post-acquisition integration. This expense is included in the other operation and maintenance line item on the income statement. Severance payments of $1.2 million were made during 2015, leaving a severance accrual of $5.4 million on our balance sheet at December 31, 2015. Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments:
(in millions) 2015
Electric utility segment $5.8
Natural gas utility segment 0.7
Steam utility segment 0.1
Total severance expense $6.6

NOTE 3—RELATED PARTIES

We and our subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, ATC, and other entities in which we have material interests.

We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the acquisition of Integrys by Wisconsin Energy Corporation on June 29, 2015, an affiliated interest agreement (Non-WBS AIA) went into effect. The Non-WBS AIA governs the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS will continue to provide services to Integrys and its subsidiaries only under the existing WBS affiliated interest agreements (WBS AIAs). WBS will provide services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us, under new interim WBS affiliated interest agreements (interim WBS AIAs). The PSCW and all other relevant state commissions have approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA.

Services under the Non-WBSAIA are subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary are priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary are priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary are priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS are priced at cost.

WBSprovides 15 categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBSAIAs, which have been approved, or from which we have been granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the interim WBS AIAs. Other modifications or amendments to the interim WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases.

The PSCW orders approving the Non-WBS AIA and the interim WBS AIAs include an April 1, 2016 sunset date for WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us. We may request one extension of the sunset date. Prior to the sunset date, we, along with WEC Energy Group, will file new or modified Non-WBS and WBS AIAs for approval with the PSCW and other state commissions.

We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost. See Note 4, Investment in American Transmission Company, for more information.

Bostco, our consolidated subsidiary, has a note payable to our parent company, WEC Energy Group. At December 31, 2015 and 2014, the balance of this note payable was $19.6 million and $22.4 million, respectively.


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The following table shows activity associated with our related party transactions for the years ended December 31:
(in millions) 2015 2014 2013
Lease agreements  
  
  
Lease payments to We Power (1)
 $410.5
 $389.0
 $405.8
Construction work in progress billed to We Power 58.8
 41.0
 21.9
Electric transactions    
  
Purchases from Wisconsin Public Service Corporation 0.1
 —
 —
Natural gas transactions    
  
Purchases from Wisconsin Gas 5.3
 6.6
 5.4
Purchases from Wisconsin Public Service Corporation 0.4
 —
 —
Interest expense (2)
  
  
  
WEC Energy Group 1.3
 1.5
 1.4

(1)
We make lease payments to We Power, a subsidiary of WEC Energy Group, for PWGS 1, PWGS 2, OC 1, and OC 2.

(2)
Bostco has a note payable to our parent company, WEC Energy Group.

NOTE 4—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

We own approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC. We have one representative on ATC's ten-member board of directors. Each member of the board has only one vote. Due to voting requirements, no individual board member has more than 10% of the voting control. The following table shows changes to our investment in ATC during the years ended December 31:
(in millions) 2015 2014 2013
Balance at beginning of period $372.9
 $354.1
 $332.6
Add: Earnings from equity method investment 47.8
 57.9
 60.2
Add: Capital contributions 4.6
 11.5
 9.2
Less: Distributions received 42.9
 50.5
 47.8
Less: Other 0.2
 0.1
 0.1
Balance at end of period $382.2
 $372.9
 $354.1

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 the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service. The following table summarizes our significant related party transactions with ATC during the years ended December 31:
(in millions) 2015 2014 2013
Charges to ATC for services and construction $9.7
 $8.1
 $9.0
Charges from ATC for network transmission services 238.5
 231.4
 234.2

As of December 31, 2015 and 2014, our balance sheets included the following receivables and payables related to ATC:
(in millions) 2015 2014
Accounts receivable    
Services provided to ATC $0.6
 $0.6
Accounts payable    
Services received from ATC 19.9
 19.3

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Summarized financial data for ATC is included in the tables below:
(in millions) 2015 2014 2013
Income statement data      
Revenues $615.8
 $635.0
 $626.3
Operating expenses 319.3
 307.4
 295.0
Other expense 96.1
 88.9
 83.7
Net income $200.4
 $238.7
 $247.6

(in millions) December 31, 2015 December 31, 2014
Balance sheet data    
Current assets $80.5
 $66.4
Noncurrent assets 3,957.6
 3,728.7
Total assets $4,038.1
 $3,795.1
     
Current liabilities $330.3
 $313.1
Long-term debt 1,800.0
 1,701.0
Other noncurrent liabilities 245.0
 163.8
Shareholders' equity 1,662.8
 1,617.2
Total liabilities and shareholders' equity $4,038.1
 $3,795.1

NOTE 5—SUPPLEMENTAL CASH FLOW INFORMATION
(in millions) 2015 2014 2013
Cash paid for interest, net of amount capitalized $116.2
 $117.9
 $120.5
Cash paid (received) for income taxes, net of refunds 58.5
 20.8
 (39.2)
       
Significant non-cash transactions:      
Construction costs funded through accounts payable 11.7
 1.7
 4.6

NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets as of December 31:
(in millions) 2015 2014 See Note
Regulatory assets (1) (2)
      
Plant related – capital leases $674.4
 $603.0
 12
Unrecognized pension and OPEB costs (3)
 535.8
 498.2
 14
Electric transmission costs (4)
 191.5
 146.0
  
Income tax related items (5)
 177.4
 171.5
  
SSR 86.1
 —
 20
Energy efficiency programs (6)
 50.7
 62.2
  
PTF (7)
 45.4
 66.6
  
AROs 36.3
 17.6
 8
Other, net 58.3
 61.8
  
Total regulatory assets $1,855.9
 $1,626.9
  

(1)
Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in the table above.

(2)
As of December 31, 2015, we had $11.3 million of regulatory assets not earning a return and $136.6 million of regulatory assets earning a return based on short-term interest rates.

(3)
Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average future remaining service life of each plan.


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(4)
Represents amounts recoverable from customers related to transmission costs incurred that exceed amounts authorized for recovery in our current rates.

(5)
Adjustments related to deferred income taxes. As the related temporary differences reverse, we prospectively collect taxes from customers for which deferred taxes were recorded in prior years.

(6)
Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards.

(7)
Represents amounts recoverable from customers related to our costs of the PTF units, including subsequent capital additions.

The following regulatory liabilities were reflected on our balance sheets as of December 31:
(in millions) 2015 2014
Regulatory liabilities    
Removal costs (1)
 $696.9
 $571.2
Mines deferral (2)
 31.6
 —
Other, net 12.7
 44.7
Total regulatory liabilities $741.2
 $615.9

(1)
Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.

(2)
Represents the deferral of margins from the sales to the mines, which were not included in the 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding.

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31:

(in millions) 2015 2014
Electric utility $9,305.9
 $9,024.8
Natural gas utility 1,089.6
 1,025.4
Steam utility 104.1
 101.5
Common utility 363.5
 339.6
Total utility property, plant, and equipment 10,863.1
 10,491.3
Less: Accumulated depreciation 3,447.2
 3,392.4
Net 7,415.9
 7,098.9
Construction work in progress 170.3
 140.9
Net utility property, plant, and equipment 7,586.2
 7,239.8
     
Property under capital leases 2,876.7
 2,848.6
Less: Accumulated amortization 735.0
 633.6
Net leased facilities 2,141.7
 2,215.0
     
Non-utility and other property, plant, and equipment 54.0
 53.1
Less: Accumulated depreciation 14.7
 13.7
Net 39.3
 39.4
Construction work in progress 0.3
 —
Net non-utility and other property, plant, and equipment 39.6
 39.4
     
Total property, plant, and equipment $9,767.5
 $9,494.2


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NOTE 8—ASSET RETIREMENT OBLIGATIONS

We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities, the removal and dismantlement of generation facilities, and the closure of fly-ash landfills at our generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. On our balance sheets, AROs are recorded within other long-term liabilities.

The following table shows changes to our AROs:
(in millions) 2015 2014 2013
Balance as of January 1 $40.5
 $39.4
 $41.5
Accretion 2.3
 2.2
 2.2
Additions 15.9
*—
 —
Liabilities settled —
 (1.1) (4.3)
Balance as of December 31 $58.7
 $40.5
 $39.4

*An ARO was recorded during 2015 for the fly-ash landfills located at our generation facilities.

NOTE 9—COMMON EQUITY

Share-Based Compensation Plans

The following table summarizes our pre-tax share-based compensation expense and the related tax benefit for the year ended December 31:
(in millions) 2015 2014 2013
Stock options $3.2
 $3.6
 $3.8
Restricted stock 2.1
 2.1
 1.6
Performance units 7.5
 12.7
 11.9
Share-based compensation expense $12.8
 $18.4
 $17.3
Related tax benefit $5.1
 $7.4
 $6.9

Stock-based compensation capitalized was not significant during 2015, 2014, and 2013.

Stock Options

The following is a summary of our employees' WEC Energy Group stock option activity during 2015:
  Number of Options Weighted-Average Exercise Price 
Weighted-Average Remaining Contractual Life (in years)
 
Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2015 6,450,277
 $30.07
    
Granted 495,550
 $52.90
    
Exercised (1,258,113) $23.19
    
Outstanding as of December 31, 2015 5,687,714
 $33.58
 5.7 $101.6
Exercisable as of December 31, 2015 3,087,219
 $26.90
 4.0 $75.4

The intrinsic value of WEC Energy Group options exercised during the years ended December 31, 2015, 2014, and 2013 was
$34.6 million, $47.5 million, and $41.2 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $29.2 million, $47.9 million, and $45.5 million during the years ended December 31, 2015, 2014, and 2013, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $14.0 million, $18.8 million, and $16.6 million, respectively.

As of December 31, 2015, total compensation costs not yet recognized related to non-vested WEC Energy Group stock options held by our employees was approximately $1.5 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

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During the first quarter of 2016, the Compensation Committee awarded 94,740 non-qualified stock options with an exercise price of $50.93 to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following activity related to WEC Energy Group restricted stock held by our employees occurred during 2015:
  Number of Shares Weighted-Average Grant Date Fair Value
Outstanding as of January 1, 2015 100,657
 $38.81
Granted 126,155
 $50.75
Released (50,230) $37.73
Forfeited (1,139) $46.26
Outstanding as of December 31, 2015 175,443
 $47.66
On July 31, 2015, the Compensation Committee awarded certain of our officers and other employees an aggregate of 82,943 shares of WEC Energy Group restricted stock for the key role each played in WEC Energy Group's acquisition of Integrys. The restricted stock vests in three equal installments on January 29, 2016, January 31, 2017, and July 31, 2018.

The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $2.7 million, $2.3 million, and
$2.8 million for the years ended December 31, 2015, 2014, and 2013, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $1.1 million, $0.9 million, and $1.1 million, respectively.

As of December 31, 2015, total compensation cost not yet recognized related to our share of WEC Energy Group restricted stock was approximately $2.2 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

During the first quarter of 2016, the Compensation Committee awarded 8,211 restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Performance Units

In January 2015, 2014, and 2013, the Compensation Committee awarded 187,450; 224,735; and 230,245 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan. Performance units earned as of December 31, 2015, 2014, and 2013 vested and were settled during the first quarter of 2016, 2015, and 2014, and had a total intrinsic value of $13.0 million, $11.6 million, and $13.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $4.4 million, $4.2 million, and $4.7 million, respectively. As of December 31, 2015, total compensation cost related to performance units not yet recognized was approximately $11.8 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

During the first quarter of 2016, the Compensation Committee awarded 35,700 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restrictions

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

In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 51%. A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level.

We may not pay common dividends to WEC Energy Group under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to

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declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.

See Note 11, Short-Term Debt and Lines of Credit for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2015, restricted retained earnings totaled $1.9 billion. Our equity in undistributed earnings of investees accounted for by the equity method was $125.0 million at December 31, 2015.

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

NOTE 10—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2015 and 2014:
(in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total
$100 par value, Six Per Cent. Preferred Stock 45,000
 44,498
 —
 $4.4
$100 par value, Serial Preferred Stock 2,286,500
      
3.60% Series   260,000
 $101
 26.0
$25 par value, Serial Preferred Stock 5,000,000
 —
 —
 —
Total preferred stock       $30.4

NOTE 11—SHORT-TERM DEBT AND LINES OF CREDIT

Our commercial paper balance and the corresponding weighted-average interest rate as of December 31 are shown in the following table:
  2015 2014
(in millions, except percentages) Balance Balance
Commercial paper    
Amount outstanding at December 31 $144.0
 $306.8
Average interest rate on amounts outstanding at December 31 0.70% 0.25%
Average amounts outstanding during the year * 159.2
 179.5

*Based on daily outstanding balances during the year.

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

As of December 31, 2015, we had approximately $338.0 million of available capacity under our bank back-up credit facility and $144.0 million of commercial paper outstanding that was supported by the credit facility. As of December 31, 2015, our subsidiary had a $19.6 million note payable to WEC Energy Group with a weighted-average interest rate of 5.15%.

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31:
(in millions) Maturity 2015
Revolving credit facility December 2020 500.0
Total short-term credit capacity   $500.0
     
Less:    
Letters of credit issued inside credit facility   $18.0
Commercial paper outstanding   144.0
     
Available capacity under existing agreement   $338.0


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In December 2015, we amended our credit facility to extend its expiration to December 2020. The facility has a renewal provision for two one-year extensions, subject to lender approval.

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

NOTE 12—LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

See our statements of capitalization for details on our long-term debt.

In May 2015, we issued $250.0 million of 3.10% Debentures due June 1, 2025. The net proceeds were used to repay short-term debt and for general corporate purposes.

In November 2015, we issued $250.0 million of 4.30% Debentures due December 15, 2045. The proceeds were used to repay short-term debt, to repay a portion of our $250.0 million of 6.25% Debentures that matured on December 1, 2015, and for working capital and other corporate purposes.

Debentures and Notes

As of December 31, 2015, the maturities of our long-term debt outstanding (excluding obligations under capital leases) were as follows:
(in millions)  
2016 $—
2017 —
2018 250.0
2019 250.0
2020 —
Thereafter 2,187.0
Total $2,687.0

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

We are the obligor under two series of tax-exempt pollution control refunding bonds in an outstanding principal amount of $147.0 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2015 and 2014, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt or included in our capitalization statements because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Obligations Under Capital Lease

We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under capital lease accounting, we have recorded the leased plants and corresponding obligations under the capital leases on our balance sheets. We treat these agreements as operating leases for rate-making purposes. We record our minimum lease payments under the power purchase contract as purchased power expense on our income statements. We record the lease payments under our PTF leases as rent expense in other operation and maintenance in our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. See Note 6, Regulatory Assets and Liabilities, for more information on our plant related capital leases.


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Power Purchase Commitment

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

PWGS

We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. The leased plants and corresponding obligations for the plants have been recorded at the estimated fair value of $692.5 million. We are amortizing the leased plants on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.4 million in the year 2021 for PWGS 1 and to approximately $130.1 million in the year 2024 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for the plants was $636.5 million as of December 31, 2015, and will decrease to zero over the remaining lives of the contracts.

Oak Creek Expansion

We are leasing OC 1, OC 2 and the common facilities, which are also utilized by our Oak Creek Units 5-8, from We Power under PSCW approved leases. We are amortizing the leased plants on a straight-line basis over the 30-year term of the leases. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively. The leased plants and corresponding capital lease obligations have been recorded at the estimated fair value of $2,043.9 million. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $541.3 million in the year 2029 for OC 1 and to approximately $445.3 million in the year 2030 for OC2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases was $2,119.7 million as of December 31, 2015, and will decrease to zero over the remaining lives of the contracts.

We paid the following lease payments during 2015, 2014, and 2013:
(in millions) 2015 2014 2013
Long-term power purchase commitment $36.2
 $34.9
 $33.7
PWGS  103.8
 99.2
 99.1
Oak Creek expansion 306.7
 277.8
 274.9
Total $446.7
 $411.9
 $407.7


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The following table summarizes our capitalized leased facilities as of December 31:
(in millions) 2015 2014
Long-term power purchase commitment    
Under capital lease $140.3
 $140.3
Accumulated amortization (103.9) (98.3)
Total long-term power purchase commitment $36.4
 $42.0
     
PWGS     
Under capital lease $692.5
 $682.7
Accumulated amortization (245.7) (217.6)
Total PWGS  $446.8
 $465.1
     
Oak Creek expansion    
Under capital lease $2,043.9
 $2,025.6
Accumulated amortization (385.4) (317.7)
Total Oak Creek $1,658.5
 $1,707.9
     
Total leased facilities $2,141.7
 $2,215.0

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2015 are as follows:
(in millions) Power Purchase Commitment PWGS Oak Creek Expansion Total
2016 $45.1
 $100.8
 $313.6
 $459.5
2017 13.9
 100.8
 314.0
 428.7
2018 14.7
 100.8
 314.0
 429.5
2019 15.5
 100.8
 314.0
 430.3
2020 16.4
 100.8
 314.0
 431.2
Thereafter 24.9
 1,101.5
 6,116.9
 7,243.3
Total minimum lease payments 130.5
 1,605.5
 7,686.5
 9,422.5
Less: Estimated executory costs (47.4) —
 —
 (47.4)
Net minimum lease payments 83.1
 1,605.5
 7,686.5
 9,375.1
Less: Interest (23.2) (969.0) (5,566.8) (6,559.0)
Present value of net        
Minimum lease payments 59.9
 636.5
 2,119.7
 2,816.1
Less: Due currently (30.3) (11.8) (81.5) (123.6)
Long-term obligations under capital lease $29.6
 $624.7
 $2,038.2
 $2,692.5

NOTE 13—INCOME TAXES

Income Tax Expense

The following table is a summary of income tax expense for each of the years ended December 31:
(in millions) 2015 2014 2013
Current tax expense $33.1
 $31.2
 $7.3
Deferred income taxes, net 180.0
 192.5
 194.7
Investment tax credit, net (1.1) (1.1) (1.1)
Total income tax expense $212.0
 $222.6
 $200.9


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Statutory Rate Reconciliation

The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following:
  2015 2014 2013
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate
Expected tax at statutory federal tax rates $205.7
 35.0 % $209.8
 35.0 % $196.3
 35.0 %
State income taxes net of federal tax benefit 31.0
 5.3 % 33.0
 5.5 % 31.7
 5.6 %
Production tax credits (17.8) (3.0)% (17.4) (2.9)% (16.7) (3.0)%
Domestic production activities deduction (7.8) (1.3)% —
 — % —
 — %
AFUDC – Equity (2.0) (0.3)% (1.5) (0.2)% (6.1) (1.1)%
Treasury grant (1.7) (0.3)% (3.8) (0.6)% (7.4) (1.3)%
Investment tax credit restored (1.1) (0.2)% (1.1) (0.2)% (1.1) (0.2)%
Other, net 5.7
 0.8 % 3.6
 0.5 % 4.2
 0.7 %
Total income tax expense $212.0
 36.0 % $222.6
 37.1 % $200.9
 35.7 %

Deferred Income Tax Assets and Liabilities

The components of deferred income taxes as of December 31 were as follows:
(in millions) 2015 2014
Deferred tax assets    
Deferred revenues $219.9
 $221.3
Employee benefits and compensation 103.2
 103.8
Future federal tax benefits 72.9
 56.0
Construction advances 17.7
 15.5
Uncollectible account expense 14.3
 15.6
Emission allowances 0.2
 0.1
Other 48.7
 35.0
Total deferred tax assets 476.9
 447.3
     
Deferred tax liabilities    
Property-related 2,058.5
 1,942.1
Investment in transmission affiliate 174.9
 164.1
Employee benefits and compensation 164.6
 131.2
Deferred transmission costs 76.7
 58.5
Prepaid tax, insurance, and other 50.6
 50.5
Other 61.6
 18.1
Total deferred tax liabilities 2,586.9
 2,364.5
Deferred tax liability, net $2,110.0
 $1,917.2

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

As of December 31, 2015, we had approximately $72.9 million of deferred tax assets associated with tax credit carryforwards. As of December 31, 2014, we had approximately $3.9 million and $54.6 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of approximately $1.4 million and $54.6 million, respectively. These tax credit carryforwards begin to expire in 2031. We anticipate having future taxable income sufficient to utilize these deferred tax assets.

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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:
(in millions) 2015 2014
Balance as of January 1 $7.2
 $8.4
Reductions for tax positions of prior years (1.1) (1.2)
Balance as of December 31 $6.1
 $7.2

The amount of unrecognized tax benefits as of December 31, 2015 and 2014, excludes deferred tax assets related to uncertainty in income taxes of $6.1 million and $7.2 million, respectively. As of December 31, 2015 and 2014, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the year ended December 31, 2015, we recognized approximately $0.1 million of interest income in our income statements. For the years ended December 31, 2014 and 2013, we recognized approximately $0.3 million and $0.2 million, respectively, of interest expense in our income statements. For the years ended December 31, 2015, 2014, and 2013, we recognized no penalties in our income statements. We had approximately $0.6 million and $0.7 million of interest accrued on our balance sheets as of December 31, 2015 and 2014, 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 Federal and the state of Wisconsin. Currently, the tax years of 2012 through 2015 are subject to Federal examination, and the tax years 2011 through 2015 are subject to examination by the state of Wisconsin.

NOTE 14—EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We participate in WEC Energy Group's defined benefit pension plans that cover substantially all of our employees. In addition, we participate in WEC Energy Group's OPEB plans that cover substantially all of our employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

Generally, employees who started with us 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 the projected benefit obligation relates to benefits based upon years of service and final average salary. New management employees hired after December 31, 2014 receive a 6% annual company contribution to their 401(k) plan instead of being enrolled in the defined benefit plans.

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

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


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The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:
  Pension Costs OPEB Costs
(in millions) 2015 2014 2015 2014
Change in benefit obligation        
Obligation at January 1 $1,315.2
 $1,223.1
 $322.3
 $292.4
Service cost 14.7
 9.4
 9.0
 8.1
Interest cost 52.9
 59.3
 13.4
 14.4
Participant contributions —
 —
 8.8
 8.4
Plan amendments —
 —
 —
 (5.2)
Transfer to affiliates (2.4) —
 —
 —
Actuarial loss (gain) (11.5) 110.8
 (22.3) 24.3
Other accrued benefits —
 (0.1) —
 —
Benefit payments (78.3) (87.3) (18.7) (21.1)
Federal subsidy on benefits paid N/A
 N/A
 1.3
 1.0
Obligation at December 31 $1,290.6
 $1,315.2
 $313.8
 $322.3
         
Change in fair value of plan assets        
Fair value at January 1 $1,160.0
 $1,168.9
 $224.9
 $222.4
Actual return on plan assets (7.8) 71.2
 (1.5) 12.0
Employer contributions 105.0
 7.2
 2.6
 3.2
Participant contributions —
 —
 8.8
 8.4
Transfer to affiliates 0.4
 —
 —
 —
Benefit payments (78.3) (87.3) (18.7) (21.1)
Fair value at December 31 $1,179.3
 $1,160.0
 $216.1
 $224.9

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:
  Pension Costs OPEB Costs
(in millions) 2015 2014 2015 2014
Other long-term assets $—
 $—
 $1.9
 $1.9
Pension and other postretirement benefit obligations 111.3
 155.2
 99.6
 99.3
Total net liabilities $111.3
 $155.2
 $97.7
 $97.4

The accumulated benefit obligation for all defined benefit plans was $1,287.5 million and $1,314.3 million as of December 31, 2015 and 2014, respectively.

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31:
  Pension Costs OPEB Costs
(in millions) 2015 2014 2015 2014
Net regulatory assets        
Net actuarial loss $520.9
 $476.4
 $14.7
 $20.7
Prior service cost (credit) 4.3
 6.3
 (4.1) (5.2)
Total $525.2
 $482.7
 $10.6
 $15.5

We estimate that 2016 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs (credits) referred to above of $33.8 million and $(0.1) million, respectively.


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The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:
  Pension Costs OPEB Costs
(in millions) 2015 2014 2013 2015 2014 2013
Service cost $14.7
 $9.4
 $13.9
 $9.0
 $8.1
 $9.5
Interest cost 52.9
 59.3
 52.4
 13.4
 14.4
 12.7
Expected return on plan assets (83.6) (79.1) (77.2) (16.0) (16.2) (14.5)
Amortization of prior service cost (credit) 2.0
 2.0
 2.2
 (1.1) (1.7) (1.9)
Amortization of net actuarial loss 35.6
 26.9
 41.7
 1.0
 0.2
 1.5
Amortization of settlement charge —
 —
 1.5
 —
 —
 —
Net periodic benefit cost $21.6
 $18.5
 $34.5
 $6.3
 $4.8
 $7.3

Assumptions – Pension and Other Postretirement Benefit Plans

The weighted-average assumptions used to determine the benefit obligations and net periodic benefit costs for the plans were as follows for the years ended December 31:
  Pension Costs OPEB Costs
  2015 2014 2013 2015 2014 2013
Weighted-average assumptions used to determine benefit obligations as of Dec. 31            
Discount rate 4.45% 4.15% 5.00% 4.45% 4.20% 4.95%
Rate of compensation increase 4.00% 4.00% 4.00% N/A N/A N/A
             
Weighted-average assumptions used to determine net cost for year ended Dec. 31            
Discount rate 4.15% 5.00% 4.10% 4.20% 4.95% 4.15%
Expected return on plan assets 7.00% 7.25% 7.25% 7.25% 7.50% 7.50%
Rate of compensation increase 4.00% 4.00% 4.00% N/A N/A N/A
             
Assumed health care cost trend rates as of Dec. 31      
Health care cost trend rate assumed for next year (Pre 65 / Post 65)   7.5%/7.5% 7.5%/7.5% 7.5%/7.5%
Rate that the cost trend rate gradually adjusts to   5.00% 5.00% 5.00%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65) 2021/2021 2021/2021 2021/2021

WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2016, the expected return on assets assumption is 7.00% for the pension plan and 7.25% for the OPEB plan.

Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2015, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:
(in millions) 1% Increase 1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $3.2
 $(2.6)
Effect on the health care component of the accumulated postretirement benefit obligation 30.3
 (25.2)

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

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asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

Previously, our pension trust target allocation was 45% equity investments and 55% fixed income investments. A transition to a target asset allocation of 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments began in late 2014. The current OPEB trusts' target asset allocations are 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.

Pension and OPEB plan investments are recorded at fair value. See Note 1(n), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.

The following table summarizes the fair values of our investments by asset class:
  As of December 31, 2015
  Pension Plan Assets OPEB Assets
(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Asset Class                
Cash and cash equivalents $15.5
 $—
 $—
 $15.5
 $2.4
 $—
 $—
 $2.4
Equity securities:                
U.S. equity 368.4
 —
 —
 368.4
 86.6
 —
 —
 86.6
International equity 97.3
 23.9
 —
 121.2
 26.9
 1.6
 —
 28.5
Fixed income securities: *                
U.S. bonds 33.8
 509.5
 —
 543.3
 2.3
 78.0
 —
 80.3
International bonds 54.7
 32.6
 —
 87.3
 10.8
 4.5
 —
 15.3
Private Equity and Real Estate —
 —
 43.6
 43.6
 —
 —
 3.0
 3.0
Total $569.7
 $566.0
 $43.6
 $1,179.3
 $129.0
 $84.1
 $3.0
 $216.1

*This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.
  As of December 31, 2014
  Pension Plan Assets OPEB Assets
(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Asset Class                
Cash and cash equivalents $5.1
 $—
 $—
 $5.1
 $0.9
 $—
 $—
 $0.9
Equity securities:                
U.S. equity 404.5
 —
 —
 404.5
 98.4
 —
 —
 98.4
International equity 103.3
 23.9
 —
 127.2
 28.5
 1.7
 —
 30.2
Fixed income securities: *                
U.S. bonds 34.2
 481.2
 —
 515.4
 2.4
 75.8
 —
 78.2
International bonds 63.7
 34.8
 —
 98.5
 11.8
 4.7
 —
 16.5
Private Equity and Real Estate —
 —
 9.3
 9.3
 —
 —
 0.7
 0.7
Total $610.8
 $539.9
 $9.3
 $1,160.0
 $142.0
 $82.2
 $0.7
 $224.9

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


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The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy:
  Private Equity and Real Estate
(in millions) Pension OPEB
Beginning balance at January 1, 2015 $9.3
 $0.7
Realized and unrealized gains (losses) 1.4
 0.1
Purchases 41.8
 2.8
Liquidations (8.9) (0.6)
Ending balance at December 31, 2015 $43.6
 $3.0

  Private Equity and Real Estate
(in millions) Pension OPEB
Beginning balance at January 1, 2014 $—
 $—
Purchases 9.3
 0.7
Ending balance at December 31, 2014 $9.3
 $0.7

Cash Flows

We expect to contribute $6.6 million to the pension plans and $0.1 million to OPEB plans in 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB:
(in millions) Pension Costs OPEB Costs
2016 $96.5
 $14.4
2017 96.6
 15.6
2018 94.3
 16.7
2019 93.5
 17.8
2020 91.6
 18.6
2021-2025 429.0
 101.9

Savings Plans

We sponsor savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $13.0 million during 2015, 2014, and 2013.

NOTE 15—COMMITMENTS AND CONTINGENCIES

We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental remediation, and enforcement and litigation matters.

Unconditional Purchase Obligations

Energy Related Purchased Power Agreements

We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates.


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The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2015.
      Payments Due By Period
(in millions) Date Contracts Extend Through Total Amounts Committed 2016 2017 2018 2019 2020 Later Years
Electric utility:                
Purchased power 2031 $95.4
 $29.4
 $25.5
 $19.3
 $5.3
 $3.3
 $12.6
Coal supply and transportation 2018 410.3
 212.9
 130.9
 66.5
 —
 —
 —
Nuclear 2033 10,012.5
 412.8
 415.3
 420.0
 445.4
 475.1
 7,843.9
Natural gas utility supply and transportation 2024 257.3
 58.3
 47.1
 43.9
 40.0
 30.9
 37.1
Total   $10,775.5
 $713.4
 $618.8
 $549.7
 $490.7
 $509.3
 $7,893.6

Operating Leases

We lease various property, plant, and equipment with various terms in the operating leases. The operating leases generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value, or (b) exercise a renewal option, as set forth in the lease agreement.

Rental expense attributable to operating leases was $6.7 million, $4.8 million, and $4.0 million in 2015, 2014, and 2013, respectively.

Future minimum payments under noncancelable operating leases are payable as follows:

Year Ending December 31
 
Payments
(in millions)
2016 $4.9
2017 3.8
2018 3.3
2019 1.4
2020 1.3
Later years 23.1
Total $37.8

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and 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:

the development of additional sources of renewable electric energy supply;
the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;
the addition of emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules;
the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects;
the retirement of old coal plants and conversion to modern, efficient, natural gas generation and super-critical pulverized coal generation;
the beneficial use of ash and other products from coal-fired and biomass generating units; and
the remediation of former manufactured gas plant sites.

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Air Quality

Sulfur Dioxide National Air Ambient Quality Standards

The EPA issued a revised 1-Hour SO2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard.

The final rule affords state agencies latitude in rule implementation. States have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection) and make attainment designation recommendations. If a state chooses modeling and an area does not show attainment, and sources do not agree to reductions by 2017 to allow attainment, the area would be classified as nonattainment. A plan would need to be developed requiring emission reductions to bring the area back into attainment by 2023. Alternatively, if a state opted out of modeling and instead chose to install air quality monitors, and subsequently monitored nonattainment, then it would face a 2026 compliance date. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.

In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO2. The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016. SO2 emissions from PIPP are above the emission threshold, which means that the Marquette area requires action earlier than would otherwise be required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. Based upon this modeling, the state of Michigan recommended to the EPA that the Marquette area be designated as attainment. We expect that the EPA will act on this recommendation in 2016.

We believe our fleet overall is well positioned to meet the new regulation.

8-Hour Ozone National Air Ambient Quality Standards

The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule.

Mercury and Other Hazardous Air Pollutants

In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule has been remanded to the EPA to address the Supreme Court decision, but remains in effect while the EPA completes its cost evaluation.

Our compliance plans currently include capital projects for PIPP to achieve the required reductions for MATS. Construction on the addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP is essentially complete and going through final startup and tuning.

In April 2013, we received a one year MATS compliance extension from the MDEQ for PIPP through April 2016.


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Climate Change

In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan as an alternative to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and requires states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would be required to submit final plans by September 2018, either alone or in conjunction with other states. States will be required to meet interim goals over the period from 2022 through 2029, and a final goal in 2030, with the goal of reducing nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources.
Rules for existing, as well as new, modified, and reconstructed generating units became effective in October 2015. A draft Federal Plan and Model Trading Rule were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. The utilities' petition narrowly asks the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO2 equivalent reduction goal by about 10%. The state's petition asks for review of a number of aspects of the final rules, including an adjustment to reflect the Kewaunee Power Station retirement. In January 2016, we submitted comments on the draft Federal Plan and Model Trading Rule. Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency. A stakeholder process began in the middle of January 2016. Michigan plans to submit an interim plan by September 6, 2016, with a request for a two year extension for submittal of a final plan.

We are in the process of reviewing the final rule for existing generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants and biomass facility, and could have a material adverse impact on our operating costs. In October 2015, following publication of the final rule, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but on February 9, 2016, the Supreme Court stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. Therefore, it is unlikely that states will move forward on the development of state plans until the litigation is complete. In addition, on February 15, 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

We are required to report our CO2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2014, we reported aggregated CO2 equivalent emissions of approximately 23.3 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 25.3 million metric tonnes to the EPA for 2015. The level of CO2 and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2014, we reported aggregated CO2 equivalent emissions of approximately 4.4 million metric tonnes to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 3.8 million metric tonnes to the EPA for 2015.


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Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for VAPP Units 1 and 2, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in October 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in September 2016.

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our proposed intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for PWGS, Pleasant Prairie Power Plant, PIPP, and Oak Creek Power Plant Units 5 through 8. 

During 2016-2018, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towers that meet EM BTA requirements) and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived.

Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will likely require additional biological treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Oak Creek Units 5 and 6, the Pleasant Prairie units, and PIPP Units 5 through 9. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $60 million to $80 million for these biological treatment and bottom ash transport systems.

Valley Power Plant Wisconsin Pollution Discharge Elimination System Permit

The WDNR issued a WPDES permit for VAPP that became effective in January 2013. The permit contained several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements included thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure is complete. An identical modification is planned for VAPP Unit 1 in 2016. We are also currently involved in planning to meet the remaining long-term requirements.


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Land Quality

Coal Combustion Residuals Rule

In April 2015, the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule was entered into the Federal Register. The final rule regulates the disposal of coal combustion residuals as a non-hazardous waste. We do not expect the compliance costs will be significant because we currently have a program of beneficial utilization for most of our coal combustion products. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources.

Coal Combustion Product Landfill Sites

We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required some level of monitoring or remediation. Where we have become aware of these conditions, and where necessary, we have worked to define the nature and extent of the impact, if any, and work has been performed to address these conditions. During 2015, 2014 and 2013, landfill remediation expenses were not material. See Note 8, Asset Retirement Obligations, for more information about obligations related to these sites.

Renewables, Efficiency, and Conservation

Wisconsin Act 141

In 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we are required to increase our renewable energy percentage to 8.27%. To comply with these requirements, we constructed the Blue Sky Green Field wind park, the Glacier Hills wind park, and the Rothschild biomass facility. We also rely on renewable energy purchases to meet our renewable portfolio standard commitments.

We are 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 through 2022. If market conditions are favorable, we may purchase more renewable energy credits. Act 141 assigned responsibility for the administration of energy efficiency, conservation, and renewable programs to the PSCW and/or contracted third parties. The funding required by Act 141 for 2015 was 1.2% of our annual operating revenues.

Michigan Act 295

In 2008, Michigan revised the requirements for renewable energy generation by enacting Act 295. Act 295 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. 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.

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.


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We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31:
(in millions) 2015 2014
Regulatory assets $16.9
 $18.7
Reserves for future remediation 5.6
 6.5
Enforcement and Litigation Matters

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.

Paris Generating Station Wisconsin Pollution Discharge Elimination System Permit

In November 2014, the WDNR reissued the WPDES permit for the PSGS. We believed that the WDNR imposed unreasonable permit conditions with respect to temperature monitoring, the control of water treatment additive, and phosphorus discharges. To address these permit conditions, we filed a petition for a contested case hearing with the WDNR in January 2015. On the same day, we also filed a request to be covered by the statewide phosphorus variance to address one of our concerns with the permit. We reached an agreement with the WDNR with respect to the permit conditions for temperature monitoring and for restrictions related to the use of a water treatment additive. In March 2015, the WDNR issued a final WPDES permit with agreed upon modifications, and we withdrew our petition for a contested case hearing. In July 2015, the Milwaukee County Circuit Court entered a stipulation and Order for Judgment between the WDNR and Wisconsin Department of Justice. This order resolves the litigation by allowing us to maintain the ability to apply for and be covered by the statewide phosphorus variance.

Paris Generating Station Units 1 and 4 Construction Permit

In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to PSGS Units 1 and 4, allowing those units to restart after a temporary outage related to a construction permit matter with the WDNR. We received an “after the fact” permit from the WDNR, and the units are now available for service. In October, 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit.

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

Valley Power Plant Title V Air Permit

In February 2011, the WDNR renewed VAPP's Title V operating permit for five years. In March 2011, the Sierra Club petitioned the EPA for additional reductions and monitoring for particulate matter and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of this proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

Solvay Coke and Gas Site

In August 2004, we were identified as a potentially responsible party at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company of ours owned a parcel of property that is within the property boundaries of the site. In 2007, we and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. The final remedial investigation report was submitted to the EPA in December 2015, and work will now begin on the feasibility study. Under the Administrative Settlement Agreement, we did not admit to any liability for the site, waive any liability defenses, or commit to perform future site remedial activities. Our share of the costs to perform the required work and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported above.


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NOTE 16—FAIR VALUE MEASUREMENTS

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
  December 31, 2015
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $0.5
 $—
 $—
 $0.5
FTRs —
 —
 1.6
 1.6
   Petroleum products contracts 1.2
 —
 —
 1.2
Coal contracts —
 2.0
 —
 2.0
Total derivative assets $1.7
 $2.0
 $1.6
 $5.3
         
Derivative liabilities        
Natural gas contracts $9.2
 $0.2
 $—
 $9.4
   Petroleum products contracts 4.4
 —
 —
 4.4
Coal contracts —
 7.6
 —
 7.6
Total derivative liabilities $13.6
 $7.8
 $—
 $21.4

  December 31, 2014
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $0.4
 $1.9
 $—
 $2.3
FTRs —
 —
 7.0
 7.0
Coal contracts —
 3.3
 —
 3.3
Total derivative assets $0.4
 $5.2
 $7.0
 $12.6
         
Derivative liabilities        
Natural gas contracts $6.8
 $0.3
 $—
 $7.1
Coal contracts —
 0.2
 —
 0.2
Total derivative liabilities $6.8
 $0.5
 $—
 $7.3

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 17, Derivative Instruments, for more information.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
(in millions) 2015 2014 2013
Balance as of January 1 $7.0
 $3.5
 $4.7
Purchases 3.9
 15.6
 10.6
Settlements (9.3) (12.1) (11.8)
Balance as of December 31 $1.6
 $7.0
 $3.5

Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on our income statements.


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Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
  December 31, 2015 December 31, 2014
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock $30.4
 $27.3
 $30.4
 $27.1
Long-term debt including current portion * $2,658.8
 $2,888.2
 $2,412.7
 $2,759.6

*Long-term debt excludes capital lease obligations.

NOTE 17—DERIVATIVE INSTRUMENTS

The following table shows our derivative assets and derivative liabilities:
    December 31, 2015 December 31, 2014
(in millions) Balance Sheet Presentation Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Natural gas Other current $0.5
 $8.1
 $2.3
 $6.4
Natural gas Other long-term —
 1.3
 —
 0.7
Petroleum products Other current 0.9
 3.3
 —
 —
Petroleum products Other long-term 0.3
 1.1
 —
 —
FTRs Other current 1.6
 —
 7.0
 —
Coal Other current 1.7
 3.4
 2.7
 0.2
Coal Other long-term 0.3
 4.2
 0.6
 —
  Other current 4.7
 14.8
 12.0
 6.6
  Other long-term 0.6
 6.6
 0.6
 0.7
Total   $5.3
 $21.4
 $12.6
 $7.3

Our estimated notional volumes and gains (losses) were as follows:
  December 31, 2015 December 31, 2014 December 31, 2013
(in millions) Volume Gains (Losses) Volume Gains Volume Gains (Losses)
Natural gas 24.0 Dth $(12.6) 21.4 Dth $4.0
 24.0 Dth $(4.0)
Petroleum products 4.0 gallons (0.2) 9.2 gallons 0.5
 8.6 gallons 0.5
FTRs 22.8 MWh 3.2
 26.1 MWh 12.7
 25.3 MWh 14.9
Total   $(9.6)   $17.2
   $11.4

As of December 31, 2015 and 2014, we posted collateral of $14.9 million and $6.9 million, respectively, in our margin accounts.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet:
  December 31, 2015 December 31, 2014
  Derivative Derivative Derivative Derivative
(in millions) Assets Liabilities Assets Liabilities
Gross amount recognized on the balance sheet $5.3
 $21.4
 $12.6
 $7.3
Gross amount not offset on the balance sheet * (0.7) (13.5) (0.4) (6.8)
Net amount $4.6
 $7.9
 $12.2
 $0.5

*Includes cash collateral posted of $12.8 million and $6.4 million as of December 31, 2015 and 2014, respectively.

NOTE 18—VARIABLE INTEREST ENTITIES

The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.


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We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal and natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

American Transmission Company

We own approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. We do not have the power to direct the activities that most significantly impact ATC's economic performance. We instead account for ATC as an equity method investment. See Note 4, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheet at December 31, 2015 included our equity investment and accounts payable. At December 31, 2015, our equity investment was $382.2 million, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $19.9 million of accounts payable due to ATC at December 31, 2015 for network transmission services.

Purchased Power Agreement

We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural 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 6 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 $130.5 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 this contract for the years ended December 31, 2015, 2014, and 2013 were $53.6 million, $53.0 million, and $50.3 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 19—REGULATORY ENVIRONMENT

2015 Wisconsin Rate Order

In May 2014, we applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved the following rate adjustments, effective January 1, 2015:

A net bill increase related to non-fuel costs for our retail electric customers of approximately $2.7 million (0.1%) in 2015. This amount reflects the receipt of SSR payments from MISO that were higher than we anticipated when we filed our rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from a Treasury Grant that we received in connection with our biomass facility. The majority of this $26.6 million was returned to customers in the form of bill credits in 2015.
A rate increase for our retail electric customers of $26.6 million (0.9%) in 2016, related to the expiration of the bill credits provided to customers in 2015.
A rate decrease of $13.9 million (-0.5%) in 2015 related to a forecasted decrease in fuel costs.
A rate decrease of $10.7 million (-2.4%) for our natural gas customers in 2015, with no rate adjustment in 2016.
A rate increase of approximately $0.5 million (2.0%) for our Downtown Milwaukee (Valley) steam utility customers in 2015, with no rate adjustment in 2016.
A rate increase of approximately $1.2 million (7.3%) for our Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016.

Our authorized ROE was set at 10.2%, and our common equity component remained at an average of 51%. The PSCW order reaffirmed the deferral of our transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW approved a change in rate design for us, which includes higher fixed charges to better match the

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related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues we will receive under the PIPP SSR agreements. Under escrow accounting, we will record SSR revenues from MISO of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference will be deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference will be deferred and recovered from customers with interest, in a future rate case.

In January 2015, certain parties appealed a portion of the PSCW's final decision adopting our specific rate design changes, including new charges for customer-owned generation within our service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in our rate case to support a demand charge for customer-owned generation. As a result, this demand charge did not take effect on January 1, 2016. No other rates approved by the PSCW in the rate case were impacted by the Dane County Circuit Court order.

Earnings Sharing Agreement

In May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for us. See Note 2, Acquisition, for more information on this earnings sharing mechanism.

2013 Wisconsin Rate Order  

In March 2012, we initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved the following rate adjustments, effective January 1, 2013:

A net bill increase related to non-fuel costs for our retail electric customers of approximately $70.0 million (2.6%) in 2013. This amount reflected an offset of approximately $63.0 million (2.3%) for bill credits related to the proceeds of the Treasury Grant, including associated tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133.0 million (4.8%) in 2013.
An electric rate increase for our electric customers of approximately $28.0 million (1.0%) in 2014, and a $45.0 million (-1.6%) reduction in bill credits.
Recovery of a forecasted increase in fuel costs of approximately $44.0 million (1.6%) in 2013.
A rate decrease of approximately $8.0 million (-1.9%) for our natural gas customers in 2013, with no rate adjustment in 2014. The rates reflect a $6.4 million reduction in bad debt expense.
An increase of approximately $1.3 million (6.0%) for our Downtown Milwaukee (Valley) steam utility customers in 2013 and another $1.3 million (6.0%) in 2014.
An increase of approximately $1.0 million (7.0%) in 2013 and $1.0 million (6.0%) in 2014 for our Milwaukee County steam utility customers.

Based on the PSCW order, our authorized ROE remained at 10.4%. In addition, the PSCW approved escrow accounting treatment for the Treasury Grant. The PSCW also determined the construction costs for the Oak Creek expansion units were prudently incurred, and it approved the recovery of the majority of these costs in rates.

NOTE 20—MICHIGAN SETTLEMENT

In March 2015, we, along with Wisconsin Energy Corporation, entered into an Amended and Restated Settlement Agreement with the Attorney General of the State of Michigan, the Staff of the MPSC, Tilden Mining Company, and Empire Iron Mining Partnership (Amended Agreement) to resolve all objections these parties raised with the MPSC related to Wisconsin Energy Corporation's acquisition of Integrys. The agreement includes the following provisions:

The parties to the Amended Agreement agree that the acquisition satisfies the applicable requirements under Michigan law and should be approved by the MPSC.

We will not enter into an SSR agreement for the operation of PIPP so long as both mines, if operational, remain full requirements customers of ours until the earlier of (i) the date a new, clean generation plant located in the Upper Peninsula of Michigan commences commercial operation or (ii) December 31, 2019. The prior SSR agreement was terminated effective February 1, 2015, with the return of the mines as full requirements customers.


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Wisconsin Energy Corporation commits to invest, either through an ownership interest or a purchased power agreement, or to have, if formed, a future Michigan jurisdictional utility invest, in a plant subject to the issuance of a Certificate of Necessity from the MPSC. The costs of this plant would be recovered from Michigan customers.

In addition, in March 2015, we entered into a special contract with each of the mines to provide full requirements electric service through December 31, 2019.

In April 2015, the MPSC approved the acquisition of Integrys, the Amended Agreement, and the special contracts with the two mines.

NOTE 21—SEGMENT INFORMATION

At December 31, 2015, we reported three segments, which are described below. We manage our reportable segments separately due to their different operating and regulatory environments.

Our electric utility segment is engaged in the generation, distribution, and sale of electricity in southeastern (including metropolitan Milwaukee), east central, and northern Wisconsin and the Upper Peninsula of Michigan.

Our natural gas utility segment is engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.

Our steam utility segment produces, distributes, and sells steam to space heating and processing customers in metropolitan Milwaukee, Wisconsin.

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

All of our operations and assets are located within the United States. The following tables show summarized financial information concerning our reportable segments for the years ended December 31, 2015, 2014, and 2013.
2015 (in millions)
 Electric Utility Natural Gas Utility Steam Utility Wisconsin Electric Power Company Consolidated
Operating revenues * $3,413.4
 $399.7
 $41.0
 $3,854.1
Other operation and maintenance 1,309.1
 59.2
 16.6
 1,384.9
Depreciation and amortization 270.4
 29.1
 4.5
 304.0
Operating income 582.7
 60.6
 5.6
 648.9
Equity in earnings of transmission affiliate 47.8
 —
 —
 47.8
Capital expenditures 444.6
 71.7
 2.9
 519.2
2014 (in millions)
 Electric Utility Natural Gas Utility Steam Utility 
Wisconsin Electric Power
Company Consolidated
Operating revenues * $3,401.1
 $614.2
 $44.1
 $4,059.4
Other operation and maintenance 1,268.9
 70.0
 17.5
 1,356.4
Depreciation and amortization 244.1
 30.5
 3.7
 278.3
Operating income 565.6
 77.2
 7.6
 650.4
Equity in earnings of transmission affiliate 57.9
 —
 —
 57.9
Capital expenditures 489.3
 69.3
 3.2
 561.8

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2013 (in millions)
 Electric Utility Natural Gas Utility Steam Utility 
Wisconsin Electric Power
Company Consolidated
Operating revenues * 
 $3,308.7
 $451.9
 $39.6
 $3,800.2
Other operation and maintenance 1,323.8
 75.0
 18.5
 1,417.3
Depreciation and amortization 201.5
 25.5
 3.6
 230.6
Operating income 533.2
 69.8
 2.9
 605.9
Equity in earnings of transmission affiliate 60.2
 —
 —
 60.2
Capital expenditures 467.8
 60.0
 11.1
 538.9

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

NOTE 22—QUARTERLY FINANCIAL INFORMATION (Unaudited)
(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total
2015          
Operating revenues $1,084.6
 $883.0
 $981.1
 $905.4
 $3,854.1
Operating income 204.7
 128.7
 169.8
 145.7
 648.9
Net income attributed to common shareholder 121.4
 74.6
 100.1
 79.6
 $375.7
           
2014          
Operating revenues $1,226.7
 $905.7
 $937.8
 $989.2
 $4,059.4
Operating income 221.8
 144.2
 156.2
 128.2
 650.4
Net income attributed to common shareholder 127.0
 90.0
 89.8
 69.9
 376.7

Due to various factors, the quarterly results of operations are not necessarily comparable.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.

Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have on our financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We are currently assessing the effects this guidance may have on our financial statements.



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2012 Form 10-K

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


ITEM 9A.CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of Wisconsin Electric Power Company'sour internal control over financial reporting based on the framework in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that Wisconsin Electric Power Company'sour internal control over financial reporting was effective as of December 31, 2012.2015.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

This annual reportAnnual Report on Form 10-K does not include an attestation report of the Company'sour independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the Company'sour independent registered public accounting firm pursuant to rules of the SEC that permit the Companyus to provide only management's report in this annual report.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 20122015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On June 29, 2015, our parent company acquired Integrys. WEC Energy Group is currently in the process of integrating and aligning the operations, processes, and internal controls of the combined company. See Note 2, Acquisition, for more information regarding the acquisition.

ITEM 9B.
 OTHER INFORMATION

None


None.


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2012 Form 10-K

PART III


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

The information under "Election of Directors", "Section 16(a) Beneficial Ownership Reporting Compliance", "Corporate Governance --– Frequently Asked Questions: What is the process used to identify director nominees and how do I recommend a nominee to WEC'sWEC Energy Group's Corporate Governance Committee?", "Corporate Governance --– Frequently Asked Questions: Are the WEC Energy Group Audit and Oversight and Compensation Committees comprised solely of independent directors?", "Corporate Governance --– Frequently Asked Questions: Are all the members of the WEC Energy Group Audit Committee financially literate and does the committee have an 'audit committee financial expert'?", "Corporate Governance --– Frequently Asked Questions: Does the Board have a nominating committee?" and "Committees of the WEC Energy Group Board of Directors --– Audit and Oversight" in our Definitive Information Statement on Schedule 14C to be filed with the SEC for our Annual Meeting of Stockholders to be held April 25, 201328, 2016 (the "2013"2016 Annual Meeting Information Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.

WisconsinWEC Energy Group has adopted a written code of ethics, referred to as its Code of Business Conduct. We are a subsidiary of WisconsinWEC Energy Group, and as such, all of our directors, executive officers and employees, including our principal executive officer, principal financial officer and principal accounting officer, have a responsibility to comply with Wisconsin Energy'sWEC Energy Group's Code of Business Conduct. WisconsinWEC Energy Group has posted its Code of Business Conduct in the "Governance" section on its website, www.wisconsinenergy.com. Wisconsinwww.wecenergygroup.com. WEC Energy Group has not provided any waiver to the Code for any director, executive officer or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on Wisconsin Energy'sWEC Energy Group's website or in a current report on Form 8-K.
 

ITEM 11.EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION

The information under "Compensation Discussion and Analysis", "Executive Compensation", "Director Compensation", "Committees of the WEC Energy Group 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 20132016 Annual Meeting Information Statement is incorporated herein by reference.


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

All of our Common Stock is owned by our parent company, WisconsinWEC Energy Corporation,Group, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201. Our directors and director nominees, andwho are all executive officers of Wisconsin Electric, as well as our other executive officers, do not own any of our voting securities. The information concerning their beneficial ownership in WisconsinWEC Energy Group common stock set forth under "Stock Ownership of Directors, Nominees and Executive Officers" in the 20132016 Annual Meeting Information Statement is incorporated herein by reference.

We do not have any equity compensation plans under which our equity securities may be issued. Our directors, officers and certain employees participate in the compensation plans of WisconsinWEC Energy Corporation.Group.



102Wisconsin Electric Power Company
2012 Form 10-K

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
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 WEC Energy Group Board's standards of independence?", "Corporate Governance --– Frequently Asked Questions: Are the WEC Energy Group Audit and Oversight and Compensation Committees comprised solely of independent directors?", "Corporate Governance --– Frequently Asked Questions: Does the Company have policies and procedures in place to review and approve related party transactions?" and "Certain Relationships and Related Transactions" in the 20132016 Annual Meeting Information Statement is incorporated herein by reference. A full description of the guidelines ourthe WEC Energy Group Board uses to determine director independence is located in Appendix A of Wisconsin Energy'sWEC Energy Group's Corporate Governance Guidelines, which can be found on its website, www.wisconsinenergy.com.www.wecenergygroup.com.



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ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES
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 20132016 Annual Meeting Information Statement is incorporated herein by reference.



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PART IV


ITEM 15.
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

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, 2012.
Report of Independent Registered Public Accounting Firm.
 
66
Consolidated Balance Sheets at December 31, 2012 and 2011.
6749
    
 
Consolidated Income Statements for the three years ended December 31, 2015, 2014, and 2013.
50
Consolidated Balance Sheets at December 31, 2015 and 2014.
51
Consolidated Statements of Cash Flows for the three years ended December 31, 2012.2015, 2014, and 2013.
 
6952
    
 
Consolidated Statements of Capitalization atEquity for the three years ended December 31, 20122015, 2014, and 2011.2013.
 
7053
    
 
Consolidated Statements of Common Equity for the three years endedCapitalization at December 31, 2012.2015 and 2014.
 
7154
    
 
Notes to Consolidated Financial Statements.
 
7255
2.Financial Statement Schedules Included in Part IV of This Report
    
 Report of Independent Registered Public Accounting Firm.
100

2
FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT
Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2012.2015, 2014, and 2013.
93
  
 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.


103Wisconsin Electric Power Company
2012 Form 10-K

3
EXHIBITS AND EXHIBIT INDEX
  
 
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.
95



2015 Form 10-K10492Wisconsin Electric Power Company
Table of Contents
2012 Form 10-K

SCHEDULE II
SCHEDULE IIWISCONSIN ELECTRIC POWER COMPANY
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, 2012 $36.9
 $8.7
 $20.7
 $(29.6) $36.7
December 31, 2011 $34.2
 $46.2
 $(14.6) $(28.9) $36.9
December 31, 2010 $31.5
 $46.9
 $(14.0) $(30.2) $34.2
Allowance for Doubtful Accounts
(in millions)
 Balance at Beginning of the Period 
Expense (1)
 Deferral 
Net Write-offs (2)
 Balance at End of the Period
December 31, 2015 $46.8
 $30.6
 $0.3
 $(34.7) $43.0
December 31, 2014 $39.7
 $31.3
 $10.0
 $(34.2) $46.8
December 31, 2013 $36.7
 $31.4
 $2.7
 $(31.1) $39.7

(1)
Net of recoveries

(2)
Represents amounts written off to the reserve, net of adjustments to regulatory assets.

2015 Form 10-K10593Wisconsin Electric Power Company
Table of Contents
2012 Form 10-K

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

  WISCONSIN ELECTRIC POWER COMPANY
   
 By  /s/GALE E. KLAPPA                                            
Date:February 27, 201326, 2016Gale E. Klappa, Chairman of the Board Presidentand
  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, 201326, 2016
Gale E. Klappa, Chairman of the Board President and Chief Executive  
Executive Officer and Director -- Principal Executive Officer  
   
/s/J. PATRICK KEYES February 27, 201326, 2016
J. Patrick Keyes, Executive Vice President and Chief  
Financial Officer and Director -- Principal Financial Officer  
   
/s/STEPHEN P. DICKSON                                                         WILLIAM J. GUC February 27, 201326, 2016
Stephen P. Dickson,William J. Guc, Vice President and  
Controller -- Principal Accounting Officer  
   
/s/JOHN F. BERGSTROM                                                          J. KEVIN FLETCHER February 27, 201326, 2016
John F. Bergstrom,J. Kevin Fletcher, Director  
   
/s/BARBARAALLEN L. BOWLES                                                         LEVERETT February 27, 201326, 2016
BarbaraAllen L. Bowles,Leverett, Director  
   
/s/PATRICIA W. CHADWICK                                                   SUSAN H. MARTIN February 27, 201326, 2016
Patricia W. Chadwick,Susan H. Martin, Director  
/s/ROBERT A. CORNOG                                                            February 27, 2013
Robert A. Cornog, Director
/s/CURT S. CULVER                                                                   February 27, 2013
Curt S. Culver, Director
/s/THOMAS J. FISCHER                                                             February 27, 2013
Thomas J. Fischer, Director
/s/HENRY W. KNUEPPELFebruary 27, 2013
Henry W. Knueppel, Director
/s/ULICE PAYNE, JR.                                                                 February 27, 2013
Ulice Payne, Jr., Director
/s/MARY ELLEN STANEKFebruary 27, 2013
Mary Ellen Stanek, Director


2015 Form 10-K10694Wisconsin Electric Power Company
Table of Contents
2012 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
(Commission File No. 001-01245)

EXHIBIT INDEX
to
Annual Report on Form 10-K
For the year ended December 31, 20122015
 
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)

Number Exhibit
3 Articles of Incorporation and By-laws
    
  3.1*
Restated Articles of Incorporation of Wisconsin Electric Power Company, as amended and restated effective January 10, 1995. (Exhibit (3)-1 to Wisconsin Electric Power Company's 12/31/94 Form 10-K.)

    
  3.2*Bylaws of Wisconsin Electric Power Company, as amended to May 1, 2000. (Exhibit 3.1 to Wisconsin Electric Power Company's 03/31/00 Form 10-Q.)
    
4 Instruments defining the rights of security holders, including indentures
    
  4.1*
Reference is made to Article III of the Restated Articles of Incorporation of Wisconsin Electric Power Company. (Exhibit 3.1 herein.)


    
  IndentureIndentures and Securities Resolutions:
    
  4.2*
Indenture for Debt Securities of Wisconsin Electric Power Company (the "Wisconsin Electric Indenture"), dated December 1, 1995. (Exhibit (4)-1 to Wisconsin Electric's 12/31/95 Form 10-K.)

    
  4.3*
Securities Resolution No. 1 of Wisconsin Electric under the Wisconsin Electric Indenture, dated December 5, 1995. (Exhibit (4)-2 to Wisconsin Electric's 12/31/95 Form 10-K.)


    
  4.4*
Securities Resolution No. 23 of Wisconsin Electric under the Wisconsin Electric Indenture, dated November 12, 1996.May 27, 1998. (Exhibit 4.44(4)-1 to Wisconsin Energy Corporation's 12/31/96Electric's 06/30/98 Form 10-K (File No. 001-09057).10-Q.)

    
  4.5*
Securities Resolution No. 5 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to Wisconsin Electric's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)


    
  4.6*
Securities Resolution No. 7 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 2, 2006. (Exhibit 4.1 to Wisconsin Electric's 11/02/06 Form 8-K, dated November 2, 2006.8-K.)


    
  4.7*
Securities Resolution No. 8 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of September 25, 2008. (Exhibit 4.1 to Wisconsin Electric's 09/25/08 Form 8-K.)



E-1Wisconsin Electric Power Company
2012 Form 10-K

NumberExhibit
4.8*
Securities Resolution No. 9 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2008. (Exhibit 4.1 to Wisconsin Electric's 12/08/08 Form 8-K.)



4.9*
Securities Resolution No. 10 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2009. (Exhibit 4.1 to Wisconsin Electric's 12/08/09 Form 8-K.)


    
  4.10*4.8*
Securities Resolution No. 11 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of September 7, 2011. (Exhibit 4.1 to Wisconsin Electric's 09/07/11 Form 8-K.)


    
  4.11*4.9*
Securities Resolution No. 12 of Wisconsin Electric Underunder the Wisconsin Electric Indenture, dated as of December 5, 2012. (Exhibit 4.1 to Wisconsin Electric's 12/05/12 Form 8-K.)
4.10*Securities Resolution No. 13 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of June 10, 2013. (Exhibit 4.1 to Wisconsin Electric’s 06/10/13 Form 8-K.)
4.11*Securities Resolution No. 14 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 12, 2014. (Exhibit 4.1 to Wisconsin Electric's 05/12/14 Form 8-K.)
4.12*Securities Resolution No. 15 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 14, 2015. (Exhibit 4.1 to Wisconsin Electric's 05/14/15 Form 8-K.)

2015 Form 10-K95Wisconsin Electric Power Company
Table of Contents


NumberExhibit
4.13*Securities Resolution No. 16 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 13, 2015. (Exhibit 4.1 to Wisconsin Electric's 11/13/15 Form 8-K.)
    
   
Certain agreements and instruments with respect to unregistered long-term debt not exceeding 10 percent of the total assets of the Registrant and its subsidiary on a consolidated basis have been omitted as permitted by related instructions. The Registrant agrees pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreements and instruments.

    
10
 Material Contracts
   
  10.1*
WisconsinWEC Energy CorporationGroup Supplemental Pension Plan, effectiveAmended and Restated Effective as of January 1, 2005.2016. (Exhibit 10.910.1 to WisconsinWEC Energy Corporation'sGroup's 12/31/082015 Form 10-K (File No. 001-09057).)** See Note.



    
  10.2*
Service Agreement, dated April 25, 2000, between Wisconsin Electric Power CompanyLegacy WEC Energy Group Executive Deferred Compensation Plan, Amended and Wisconsin Gas Company (n/k/a Wisconsin Gas LLC).Restated as of January 1, 2016. (Exhibit 10.3210.2 to WisconsinWEC Energy Corporation'sGroup's 12/31/002015 Form 10-K (File No. 001-09057).)








** See Note
    
  10.3*
Service Agreement, dated December 29, 2000, between Wisconsin Electric Power CompanyWEC Energy Group Executive Deferred Compensation Plan, Amended and American Transmission Company LLC.Restated Effective as of January 1, 2016. (Exhibit 10.3310.3 to WisconsinWEC Energy Corporation'sGroup's 12/31/002015 Form 10-K (File No. 001-09057).)


** See Note.
    
  10.4*
Executive Deferred Compensation Plan of Wisconsin Energy Corporation, as amended and restated as of July 23, 2004 (including amendments approved effective as of November 2, 2005) (the "Legacy EDCP") (Exhibit 10.2 to Wisconsin Energy Corporation's 09/30/05 Form 10-Q (File No. 001-09057).)** 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 (File No. 001-09057).)** 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 (File No. 001-09057).)** 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 Form 10-Q (File No. 001-09057).)** See Note.


    
  10.8*10.5*
First Amendment to the Legacy DDCP, effective as of January 1, 2005. (Exhibit 10.15 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.



E-2Wisconsin Electric Power Company
2012 Form 10-K

NumberExhibit
    
  10.9*10.6*
WisconsinWEC Energy CorporationGroup Directors' Deferred Compensation Plan, effectiveAmended and Restated Effective as of January 1, 2005.2016. (Exhibit 10.1610.6 to WisconsinWEC Energy Corporation'sGroup's 12/31/082015 Form 10-K (File No.001-09057)No. 001-09057).)** See Note.


    
  10.10*10.7*
WEC Energy Group Non-Qualified Retirement Savings Plan, Amended and Restated Effective as of January 1, 2016. (Exhibit 10.7 to WEC Energy Group's 12/31/2015 Form 10-K (File No. 001-09057).)** See Note.
10.8*Wisconsin Energy Corporation Death Benefit Only Plan, as amended and restated as of July 22, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/10 Form 10-Q (File No. 001-09057).)** See Note.


    
  10.11*10.9*
WisconsinWEC Energy CorporationGroup Short-Term Performance Plan, as amended and restated effective as of January 1, 2010.2016. (Exhibit 10.110.2 to WisconsinWEC Energy Corporation'sGroup's 12/03/0915 Form 8-K (File No. 001-09057).)** See Note.


    
  10.12*10.10*
WisconsinWEC Energy CorporationGroup Amended and Restated Executive Severance Policy, effective as of January 1, 2008. (Exhibit 10.18 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.


    
  10.13*10.11*
Restated Non-QualifiedWisconsin Energy Corporation 2014 Rabbi Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 11, 2004,23, 2015, regarding the 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 10.1610.13 to Wisconsin Energy Corporation's 12/31/0714 Form 10-K (File No. 001-09057).)** See Note.


    
  10.14*10.12*
Affiliated Interest Agreement (Service Agreement), dated December 12, 2002, by and among Wisconsin Energy Corporation and its affiliates. (Exhibit 10.14 to Wisconsin Energy Corporation's 12/31/02 Form 10-K (File No. 001-09057).)

10.15*
Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Gale E. Klappa, dated as of December 29, 2008. (Exhibit 10.25 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

    
  10.16*10.13*
Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Allen L. Leverett, dated as of December 30, 2008. (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

    
  10.17*10.14*
Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Frederick D. Kuester, dated as of December 30, 2008. (Exhibit 10.27 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** 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 (File No. 001-09057).)**See Note.

10.19*
Terms of Employment for J. Patrick Keyes. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/201212 Form 10-Q (File No. 001-09057).)** See Note.

    
  10.20*10.15*Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of December 20, 2010. (Exhibit 10.20 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.

2015 Form 10-KE-396Wisconsin Electric Power Company
Table of Contents
2012 Form 10-K

Number Exhibit
   
 
  10.21*10.16*Amendment to the Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of August 15, 2011. (Exhibit 10.21 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.
    
  10.22*10.17*
Terms of Employment for Susan H. Martin. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/12 Form 10-Q (File No. 001-09057).)**See Note.

    
  10.23*
Letter Agreement by and between Wisconsin Energy Corporation and James C. Fleming, dated as of November 23, 2005, which became effective January 3, 2006. (Exhibit 10.31 to Wisconsin Energy Corporation's 12/31/05 Form 10-K (File No. 001-09057).)** See Note.

10.24*
Amendment to the Letter Agreement between Wisconsin Energy Corporation and James C. Fleming, dated December 23, 2008. (Exhibit 10.29 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

10.25*
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 (File No. 001-09057).)** See Note.

10.26*
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 (File No. 001-09057).)**See Note.

10.27*
Supplemental Pension Benefit agreement between Wisconsin Energy Corporation and Stephen Dickson, effective May 23, 2001. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/01 Form 10-Q (File No. 001-09057).)** See Note.

10.28*
Amendment to the Supplemental Pension Benefit Agreement between Wisconsin Energy Corporation and Stephen P. Dickson, dated December 29, 2008. (Exhibit 10.32 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

10.29*
Amended and Restated Non-Compete and Special Severance Tax Protection Agreement between Wisconsin Energy Corporation and Stephen P. Dickson, effective as of January 1, 2008. (Exhibit 10.33 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

10.30*10.18*
Letter Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q
(File No. 001-09057).)** See Note.

    
  10.31*10.19*
Letter Agreement by between Wisconsin Energy Corporation1993 Omnibus Stock Incentive Plan, Amended and Joseph Kevin Fletcher, datedRestated Effective as of August 17, 2011.January 1, 2016. (Exhibit 10.110.19 to WisconsinWEC Energy Corporation's 09/30/11Group's 12/31/15 Form 10-Q10-K (File No. 001-09057).)** See Note.

    
  10.32*10.20*
2001 Revised forms of award agreements under 1993 Omnibus Stock Incentive Plan for restricted stock awards, incentive stock option awards and non-qualified stock option awards. (Exhibit 10.3 to Wisconsin Energy Corporation's 03/31/01 Form 10-Q (File No. 001-09057).)** See Note.


E-4Wisconsin Electric Power Company
2012 Form 10-K

NumberExhibit
10.33*
1993 Omnibus Stock Incentive Plan, amended and restated effective as of May 5, 2011, as approved by Wisconsin Energy Corporation's stockholders at its 2011 annual meeting of stockholders. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/11 Form 10-Q (File No. 001-09057).)** See Note.

10.34*
2005 Terms and Conditions Governing Non-Qualified Stock Option Award under 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/28/04 Form 8-K (File No. 001-09057).)** See Note.

    
  10.35*10.21*
Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/07 Form 10-Q (File No. 001-09057).)** See Note.

    
  10.36*10.22*
Terms and Conditions Governing Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan, approved December 3, 2009. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/03/09 Form 8-K (File No. 001-09057).) ** See Note.

10.37*
Terms and Conditions Governing Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan, approved December 1, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/01/10 Form 8-K (File No. 001-09057).)** See Note.

    
  10.38*10.23*
Wisconsin Energy Corporation Terms and Conditions Governing Director Restricted Stock Award under the 1993 Omnibus Stock Incentive Plan amended and restated effective May 5, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 01/19/12 Form 8-K (File No. 001-09057).)** See Note.

    
  10.39*10.24*
Wisconsin2016 WEC Energy Corporation Performance UnitGroup Terms and Conditions Governing Director Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan amended and restated effective as of January 1, 2010. (Exhibit 10.210.24 to WisconsinWEC Energy Corporation'sGroup's 12/03/0931/15 Form 8-K10-K (File No. 001-09057).)** See Note.

    
  10.40*10.25*
Form of Award of Performance Units under the WisconsinWEC Energy CorporationGroup Performance Unit Plan.Plan, amended and restated effective as of January 1, 2016. (Exhibit 10.210.1 to WisconsinWEC Energy Corporation'sGroup's 12/06/0403/15 Form 8-K (File No. 001-09057).)** See Note.

    
  10.41*10.26*
Wisconsin Energy Corporation Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.
10.27*2016 WEC Energy Group Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.27 to WEC Energy Group’s 12/31/15 Form 10-K (File No. 001-09057).)** See Note.
10.28*Wisconsin Energy Corporation Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.
10.29*2016 WEC Energy Group Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.29 to WEC Energy Group’s Form 12/31/15 Form 10-K (File No. 001-09057).)** See Note.
10.30*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'sElectric's 06/30/03 Form 10-Q.)

    
  10.42*10.31*
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'sElectric's 06/30/03 Form 10-Q.)

    
  10.43*10.32*
Elm Road I Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

    

2015 Form 10-K97Wisconsin Electric Power Company
Table of Contents

NumberExhibit
  10.44*10.33*
Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

 

E-5Wisconsin Electric Power Company
2012 Form 10-K

NumberExhibit
   
  10.45*10.34*
Point Beach Nuclear Plant Power Purchase Agreement between FPL Energy Point Beach, LLC and Wisconsin Electric Power Company, dated as of December 19, 2006 (the "PPA"). (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/08 Form 10-Q (File No. 001-09057).)

    
  10.46*10.35*
Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC, dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K (File No. 001-09057).)

10.36*Terms and Conditions for July 31, 2015 Special Restricted Stock Award. (Exhibit 10.1 to WEC Energy Group’s 6/30/15 Form 10-Q (File No. 001-09057).)** See Note.
    
  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
    
  21.1Subsidiaries of Wisconsin Electric Power Company.
    
23
 Consents of experts and counsel
    
  23.1Deloitte & Touche LLP -– Milwaukee, WI, Consent of Independent Registered Public Accounting Firm.
    
31
 Rule 13a-14(a)/15d-14(a) Certifications
    
  31.1Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
    
  31.2Certification 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
    
  32.1Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
    
  32.2Certification 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


2015 Form 10-KE-698Wisconsin Electric Power Company