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, 20132016

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 [ ]    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, 20132016 (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, 2014):

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, 2017


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 24, 2014,27, 2017, are incorporated by reference into Part III hereof.


2013 Form 10-K


WISCONSIN ELECTRIC POWER COMPANY
FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2013



WISCONSIN ELECTRIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2016
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 SEGMENT
3
 
2.       Properties
C.
32OTHER SEGMENT
12
 
3.       Legal Proceedings
D.
33REGULATION
12
 
4.       Mine Safety Disclosures
E.
34ENVIRONMENTAL COMPLIANCE
15
 
F.
EMPLOYEES
15
Executive Officers of the Registrant
ITEM 1A.
35RISK FACTORS
16
ITEM 1B.
UNRESOLVED STAFF COMMENTS
24
ITEM 2.
PROPERTIES
25
ITEM 3.
LEGAL PROCEEDINGS
26
ITEM 4.
MINE SAFETY DISCLOSURES
26
 
PART II
EXECUTIVE OFFICERS OF THE REGISTRANT
27
5.       Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
          Equity SecuritiesPART II
3728
ITEM 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
28

ITEM 6.
SELECTED FINANCIAL DATA
29
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
30
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
46
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
47
 
A.
Report of Independent Registered Public Accounting Firm
47
6.       Selected Financial Data
38B.
Consolidated Income Statements
48
C.
Consolidated Balance Sheets
49
D.
Consolidated Statements of Cash Flows
50
E.
Consolidated Statements of Equity
51
F.
Consolidated Statements of Capitalization
52
G.
Notes to Consolidated Financial Statements
53
  
7.       Management's Discussion and Analysis of Financial Condition and Results of Operations
Note 1
39Summary of Significant Accounting Policies
53
  
7A.    Quantitative and Qualitative Disclosures About Market Risk
Note 2
65Acquisitions
58
  
Note 3
Dispositions
59
8.       Financial Statements
Note 4
Related Parties
59
Note 5
Investment in American Transmission Company
61
Note 6
Supplemental Cash Flow Information
62
Note 7
Regulatory Assets and Supplementary DataLiabilities
62
Note 8
Property, Plant, and Equipment
63
Note 9
Asset Retirement Obligations
63
Note 10
Common Equity
64
Note 11
Preferred Stock
66
 Consolidated Income Statements
Note 12
Short-Term Debt and Lines of Credit
66
 Consolidated Balance Sheets -- Assets
67
 Consolidated Balance Sheets -- Capitalization and Liabilities
68Note 13
Consolidated Statements of Cash Flows
69
Consolidated Statements of Capitalization
70
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
77
Note GIncome Taxes
77
Note HCommon Equity
79
Note IPreferred Stock
82
Note JLong-Term Debt and Capital Lease Obligations
8367
 Note KShort-Term Debt
85Note 14
Income Taxes
69
 Note LDerivative Instruments
86Note 15
Employee Benefits
71
Note 16
Commitments and Contingencies
76
Note 17
Fair Value Measurements
81
Note 18
Derivative Instruments
82

2016 Form 10-K3iWisconsin Electric Power Company
Table of Contents
2013 Form 10-K

TABLE OF CONTENTS - (Cont'd)

Item  Page
Note 19
Variable Interest Entities
83
 Note MFair Value Measurements
87Note 20
Regulatory Environment
84
 
Note N21
Benefits
Segment Information
85
Note 22
Quarterly Financial Information (Unaudited)
86
Note 23
New Accounting Pronouncements
86
ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
89

ITEM 9A.
CONTROLS AND PROCEDURES
89
ITEM 9B.
Note O
OTHER INFORMATION
Segment Reporting
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
ITEM 16.
FORM 10-K SUMMARY
92
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
93
SIGNATURES
94
Note PRelated Parties
EXHIBIT INDEX
95
Note QCommitments and Contingencies
97
Note RSupplemental Cash Flow Information
98
Note SSubsequent Events
98
Report of Independent Registered Public Accounting Firm
99
9.       Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
100
9A.   Controls and Procedures
100
9B.    Other Information
100
PART III
10.    Directors, Executive Officers and Corporate Governance of the Registrant
101
11.    Executive Compensation
101
12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
         Matters
101
13.    Certain Relationships and Related Transactions, and Director Independence
102
14.    Principal Accountant Fees and Services
102
PART IV
15.    Exhibits and Financial Statement Schedules
102
Schedule II - Valuation and Qualifying Accounts
104
Signatures
105
Exhibit Index
E-1


2016 Form 10-K4iiWisconsin Electric Power Company
Table of Contents
2013 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
IntegrysIntegrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
UMERCUpper Michigan Energy Resources Corporation
WBSWEC Business Services LLC
WEWisconsin Electric Power Company
We Power W.E. Power, LLC
WisconsinWEC Energy Group WEC Energy Group, Inc. (previously known as Wisconsin Energy CorporationCorporation)
Wisconsin GasWG Wisconsin Gas LLC
WPSWisconsin Public Service Corporation
   
Significant Assets
MCPPMilwaukee County Power Plant
OC 1Oak Creek expansion Unit 1
OC 2Oak Creek expansion Unit 2
PIPPPresque Isle Power Plant
PSGSParis Generating Station
PWGSPort Washington Generating Station LLC
PWGS 1Port Washington Generating Station Unit 1
PWGS 2Port Washington Generating Station Unit 2
VAPPValley Power Plant
Other Affiliates
ATCAmerican Transmission Company LLC
DATCDuke-American Transmission Company
Federal and State Regulatory Agencies
DOEUnited States Department of Energy
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
IRSInternal Revenue Service
MDEQ Michigan Department of Environmental Quality
MPSC Michigan Public Service Commission
PSCW Public Service Commission of Wisconsin
SEC Securities and Exchange Commission
WDNR Wisconsin Department of Natural Resources
   
Accounting Terms
AFUDCAllowance for Funds Used During Construction
AROAsset Retirement Obligation
ASCAccounting Standards Codification
ASUAccounting Standards Update
CWIPConstruction Work in Progress
FASBFinancial Accounting Standards Board
GAAPGenerally Accepted Accounting Principles
OPEBOther Postretirement Employee Benefits
Environmental Terms
Act 141 2005 Wisconsin Act 141
BARTBest Available Retrofit Technology
BTABest Technology Available
CAAClean Air Act
CAIRClean Air Interstate Rule
CO2
 Carbon Dioxide
CSAPR Cross-State Air Pollution Rule

5Wisconsin Electric Power Company
2013 Form 10-K

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
GHG 
The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Greenhouse Gas
MATS Mercury and Air Toxics Standards
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
 
Measurements
DthDekatherm (One Dth equals one million Btu)
MWMegawatt (One MW equals one million Watts)
MWhMegawatt-hour

2016 Form 10-KiiiWisconsin Electric Power Company
Table of Contents

Other Terms and Abbreviations
AQCSAIA Air Quality Control SystemAffiliated Interest Agreement
ALJAdministrative Law Judge
ARRs Auction Revenue Rights
BechtelBechtel Power Corporation
Compensation Committee Compensation Committee of the Board of Directors of WisconsinWEC Energy Group, Inc.
CPCND.C. Circuit Court of Appeals CertificateUnited States Court of Public Convenience and NecessityAppeals for the District of Columbia
ERISAERGS Employee Retirement Income Security Act of 1974Elm Road Generating Station
ER 1Elm Road Generating Station Unit 1
ER 2Elm Road Generating Station Unit 2
Exchange Act Securities Exchange Act of 1934, as amended
FTRs Financial Transmission Rights
GCRM Gas Cost Recovery Mechanism
LMP Locational Marginal Price
MCPPMilwaukee County Power Plant
Merger AgreementAgreement 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 Markets MISO Energy and Operating Reserves Market
Moody'sMoody's Investor Service
NYMEX New York Mercantile Exchange
OTCOCPP Over-the-CounterOak Creek Power Plant
OC 5Oak Creek Power Plant Unit 5
OC 6Oak Creek Power Plant Unit 6
OC 7Oak Creek Power Plant Unit 7
OC 8Oak Creek Power Plant Unit 8
Omnibus Stock Incentive PlanWEC Energy Group 1993 Omnibus Stock Incentive Plan, Amended and Restated Effective as of January 1, 2016
PIPPPresque Isle Power Plant
Point Beach Point Beach Nuclear Power Plant
PTFPWGS Power the FuturePort Washington Generating Station
PWGS 1Port Washington Generating Station Unit 1
PWGS 2Port Washington Generating Station Unit 2
ROEReturn on Equity
RTO Regional Transmission Organization
S&PStandard & Poor's Ratings Services
SSR System Support Resource
Supreme CourtUnited States Supreme Court
Treasury Grant Section 1603 Renewable Energy Treasury Grant
WPLVAPP WisconsinValley Power and Light Company, a subsidiary of Alliant Energy Corp.
WolverineWolverine Power Supply Cooperative, Inc.
Measurements
BtuBritish Thermal Unit(s)
DthDekatherm(s) (One Dth equals one million Btu)
GWhGigawatt-hour(s) (One GWh equals one thousand MWh)
kWKilowatt(s) (One kW equals one thousand Watts)
kWhKilowatt-hour(s)
MWMegawatt(s) (One MW equals one million Watts)Plant


2016 Form 10-K6ivWisconsin Electric Power Company
Table of Contents
2013 Form 10-K

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
MWhMegawatt-hour(s)
WattA measure of power production or usage
Accounting Terms
AFUDCAllowance for Funds Used During Construction
AROAsset Retirement Obligation
ASUAccounting Standards Update
GAAPGenerally Accepted Accounting Principles
OPEBOther Post-Retirement Employee Benefits


7Wisconsin Electric Power Company
2013 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.Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of construction projects, retail sales and customer growth, rate actions and related filings with the appropriate regulatory authorities, current and proposed environmental regulations and other regulatory matters and related estimated expenditures, on-going legal proceedings, projections related to the pension and other post-retirement benefit plans, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, capital expenditures, liquidity and capital resources and other matters. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking 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 operations;

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, 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 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; or collective bargaining agreements with union employees or work stoppages.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; general economic conditions and, in particular,market perceptions of the economic climate in our service territories; customer growth and declines; customer business conditions, including demand for their products and services; energy conservation efforts; and customers moving to self-generation.utility industry or us;

Timing, resolutionCosts and impacteffects of 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 Midcontinent Independent System Operator, Inc. (MISO) Energy Markets, as well as any costs incurred as a result of customers moving to an alternative electric supplier.

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

Our ability to mitigate the impact of Michigan customers switching to an alternative electric supplier, including the receipt of adequate System Support Resource (SSR) payments.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 electric generation facilities, as well as upgrades to our generation fleet and 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; regulatory initiatives regarding deregulation and restructuring of the electric and/or gas utility industry; transmission or distribution system operation and/or administration initiatives; any required changes in facilities or operations to reduce the risks or impacts of potential terrorist

2016 Form 10-K81Wisconsin Electric Power Company
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION - (Cont'd)2013 Form 10-K

activities or cyber security threats; the regulatory approval process for new generation and transmission facilities and new pipeline construction; changes in environmental, federal and state energy, tax and other laws and regulations to which we are subject; changes in allocationTable of energy assistance, including state public benefits funds; changes in the application or enforcement of existing laws and regulations; and changes in the interpretation or enforcement of permit conditions by the permitting agencies.Contents

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

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

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

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

Inflation rates.

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

The financial performance of American Transmission Company LLC (ATC) and its corresponding contribution to our earnings, as well as the ability of ATC and the Duke-American Transmission Company (DATC) to obtain the required approvals for their transmission projects.

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

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

Advances in technology that result in competitive disadvantages and create the potential for impairment of existing assets.

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

The abilitydirect or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber security 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 investment performance of WEC Energy Group's employee benefit plan assets, or businesses,as well as unanticipated changes in related actuarial assumptions, which cannot be assured to be completed or beneficial to us.could impact future funding requirements;

IncidentsFactors 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;

Foreign governmental, economic, politicalAdvances in technology that result in competitive disadvantages and currency risks.create the potential for impairment of existing assets;

The timing, costs, and anticipated benefits associated with the remaining integration efforts relating to Wisconsin Energy Corporation's acquisition of Integrys;

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 factors discussedconsiderations disclosed elsewhere herein and in this report and that may be disclosed from time to time in our Securities and Exchange Commission (SEC) filingsother reports we file with the SEC or in other publicly disseminated written documents.

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


2016 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 1,128,300 electric customers in Wisconsin and served customers in the Upper Peninsula of Michigan approximately 471,300 gasthrough December 31, 2016. Effective January 1, 2017, we transferred our electric customers in Wisconsin and approximately 445 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our business segments, see Results of Operations in Item 7 and Note O -- Segment Reportingdistribution assets located in the NotesUpper Peninsula of Michigan to Consolidated Financial Statements in Item 8.

Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas),UMERC, a natural gas distributionstand-alone utility. UMERC became operational effective January 1, 2017. See Note 20, Regulatory Environment, for more information on UMERC. Our two reportable segments are utility which serves customers throughout Wisconsin; and W.E. Power, LLC (We Power), a non-utility company that was formed in 2001 to design, construct, own and lease to us the generating capacity included in Wisconsin Energy's Power the Future (PTF) strategy. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies."

other. 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, 2013, Bostco had $29.1 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, Acquisitions.

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.


UTILITY OPERATIONSYou 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 SEGMENT

ELECTRIC UTILITY OPERATIONS

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 Wisconsin, and northern Wisconsin andWisconsin.

Through December 31, 2016, we serviced electric customers in the Upper Peninsula of Michigan.

We participate Effective January 1, 2017, we transferred our electric customers and electric distribution assets located in the MISOUpper Peninsula of Michigan to UMERC, a new stand-alone utility owned by WEC Energy Markets. The competitiveness of our generation offered inGroup. UMERC obtains its energy through the MISO Energy Markets affects how our generating units are dispatched and how we buymeets its obligations through power purchase agreements with us and sell power.WPS. See Note 4, Related Parties, andNote 20, Regulatory Environment, for more information. We continue to serve an iron ore mine owned by Tilden Mining Company (Tilden) in the Upper Peninsula of Michigan. For furthermore information on the mine, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.the discussion under the heading "Large Electric Retail Customers."


2016 Form 10-K3Wisconsin Electric Power Company
Table of Contents

Operating Revenues

The following table shows electric utility operating revenues, including steam operations, for the past three years:
  Year Ended December 31
(in millions) 2016 2015 2014
Operating revenues      
Residential $1,243.3
 $1,207.6
 $1,199.3
Small commercial and industrial (1)
 1,046.1
 1,036.8
 1,054.3
Large commercial and industrial (1)
 699.3
 727.7
 640.7
Other 21.0
 22.1
 23.0
Total retail revenues (1)
 3,009.7
 2,994.2
 2,917.3
Wholesale 88.7
 101.4
 131.9
Resale 224.4
 228.2
 264.1
Steam 27.2
 41.0
 44.1
Other operating revenues (2)
 90.6
 89.6
 87.8
Total operating revenues (1)
 $3,440.6
 $3,454.4
 $3,445.2

(1)
Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

(2)
Includes SSR revenues and other revenues, partially offset by revenues from the mines that are being deferred until a future rate proceeding. For more information, see the discussion below under the heading "Large Electric Retail Customers."

Electric Sales

Our electric energy deliveries included supply and distribution sales to all classes ofretail and wholesale customers includingand distribution sales to those customers who switched to an alternative electric supplier, totaled approximately 33.0 millionsupplier. In 2016, retail electric revenues accounted for 87.5% of total electric operating revenues, while wholesale and resale electric revenues accounted for 9.1% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Utility Segment Contribution to Operating Income for information on MWh during 2013 and approximately 30.3 million MWh during 2012. We had approximately 1,128,300 electric customers as of December 31, 2013 and 1,125,700 electric customers as of December 31, 2012.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, andutilities. Through December 31, 2016, we were authorized to provide electric service in certain territories in the state of Michigan pursuant to franchises granted by municipalities. We alsowill continue to provide service to the Tilden mine located in the Upper Peninsula of Michigan pursuant to a contract between Tilden and us until UMERC's proposed generation begins commercial operation. See Note 20, Regulatory Environment, for more information.

We buy and sell wholesale electric power withinby participating in the MISO Energy Markets. The cost of our individual 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 1. Business – D. Regulation.

Steam Sales

We have a steam utility that generates, distributes, and sells steam supplied by VAPP to customers in metropolitan Milwaukee, Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions. In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. See Note 3, Dispositions, for more information.

Electric Sales Forecast

Our service territory experienced slightly declining weather-normalized retail electric sales in 2016, as positive customer growth was more than offset by reduced volumes related to lower use per customer. We currently forecast retail electric sales volumes and the associated peak demand, excluding the Tilden mine located in the Upper Peninsula of Michigan, to remain flat over the next five years, assuming normal weather.


2016 Form 10-K104Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2013 Form 10-K

Electric Sales Growth:   Our service territory experienced slightly declining retail sales in 2013 as positive customer growth was more than offset by reduced use per customer. Assuming continuing improvement in the economy over the five-year forecast horizon, we presently anticipate that total retail electric kWh sales and the associated peak electric demand will grow at annual ratesTable of about 0.5% over the next five years.These estimates assume normal weather.Contents

Sales to Customers
  Year Ended December 31
(in thousands) 2016 2015 2014
Electric customers – end of year      
Residential 1,026.0
 1,020.8
 1,015.0
Small commercial and industrial 116.7
 116.0
 115.4
Large commercial and industrial 0.7
 0.7
 0.7
Other 2.5
 2.6
 2.5
Total electric customers – end of year 1,145.9
 1,140.1
 1,133.6
       
Electric customers – average 1,143.1
 1,136.5
 1,130.7
Steam customers – average 0.4
 0.4
 0.4

Large Electric Retail Customers:Customers

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

Prior to September 2013,retail. In February 2015, our largest retail electric customers, were two iron ore mines located in the Upper Peninsula of Michigan. The combined electric energy sales to the two mines accounted for 3.7% and 6.6% of our total electric utility energy sales during 2013 and 2012, respectively.

The two iron ore mines, which we served on an interruptible tariff rate, switched toMichigan, returned as customers after choosing an alternative electric supplier effectivein September 1, 2013. For additionalmore information on alternative electric suppliers, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources --– Industry RestructuringRestructuring. We entered into a contract with each of the mines to provide full requirements electric service through December 31, 2019. Since 2015, we have been deferring, and Competitionexpect to continue to defer the revenue less cost of sales, from the mine sales and will apply these amounts for the benefit of Wisconsin retail electric customers in Item 7.a future rate proceeding.

SalesIn 2016, one of the iron ore mines closed, and the related contract for full requirements electric service was terminated. In August 2016, WEC Energy Group entered into a new agreement with the owner of the remaining mine under which it will purchase electric power from UMERC for 20 years. The agreement also calls for UMERC to construct and operate certain natural gas-fired generation located in the Upper Peninsula of Michigan. The remaining iron ore mine will continue to receive full requirements electric service from us under the existing contract, as discussed above, until UMERC's proposed generation solution in the Upper Peninsula of Michigan begins commercial operation. See Note 4, Related Parties, and Note 20, Regulatory Environment, for more information.

Wholesale Customers:   During 2013, we soldCustomers

We provide wholesale electric powerservice to two Regional Transmission Organizations (RTOs), five ruralvarious customers, including electric cooperatives, and four municipal joint action agencies, located in the states of Wisconsin and Michigan. Our wholesale electric energy sales were also made to eight other publicinvestor-owned utilities, municipal utilities, and power marketers throughout the region under rates approved by FERC.energy marketers. Wholesale sales accounted for approximately 19.7%3.2%, 3.4%, and 5.3% of our total electric energy sales during 2016, 2015, and 8.7%2014, respectively. Wholesale revenues accounted for 2.6%, 2.9%, and 3.8% of total electric operating revenues during 20132016, 2015, and 2014, respectively.

Resale

The majority 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 23.0%, compared with 10.6%23.8%, and 18.5% of total electric energy sales during 2016, 2015, and 6.2%2014, respectively. Resale revenues accounted for 6.5%, 6.6%, and 7.7% of total electric operating revenues during 2012.

Electric System Reliability Matters:   Our electric2016, 2015, and 2014, respectively. Retail fuel costs are reduced by the amount that revenue exceeds the costs of sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. The Public Service Commission of Wisconsin (PSCW) has planning reserve requirements consistent with the MISO calculated planning reserve margin. The Michigan Public Service Commission (MPSC) has not yet established guidelines in this area. In accordance with the MISO calculated planning reserve margin requirements, we had adequate capacity to meet MISO calculated planning reserve margin during 2013 and expect to have adequate capacity to meet the planning reserve margin requirements during 2014. For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Competition

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

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

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

Electric Supply 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. WeThrough our participation in the MISO Energy Markets, 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 reportunder the heading "Power Purchase Commitments," and through spot purchases in the MISO Energy Markets. We also sell excess capacity into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power.


2016 Form 10-K115Wisconsin Electric Power Company
Table of Contents
ITEM 1. BUSINESS - (Cont'd)2013 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)
  2013 2012 2011
Coal 3,822
 3,828
 3,904
Natural Gas - Combined Cycle 1,082
 1,090
 1,090
Natural Gas/Oil - Peaking Units (b) 962
 962
 967
Renewables (c) 155
 107
 80
Total 6,021
 5,987
 6,041
  
Rated Capacity in MW (1)
  2016 2015 2014
Coal 3,582
 3,589
 3,707
Natural gas:      
Combined cycle 1,140
 1,082
 1,082
Steam turbine (2)
 240
 240
 118
Natural gas/oil peaking units (3)
 962
 962
 962
Renewables (4)
 190
 187
 155
Total rated capacity 6,114
 6,060
 6,024

(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 natural gas steam turbine represents the rated capacity associated with the VAPP Units, which were converted from coal to natural gas in 2014 and 2015.

(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.

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

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2013, as well as estimates for 2017:
  Estimate Actual
  2017 2016 2015 2014
Company-owned or leased generation units:        
Coal 52.5% 49.9% 53.5% 55.2%
Natural gas:        
Combined cycle 10.4% 15.9% 13.0% 8.7%
Steam turbine 1.0% 1.2% 1.4% 0.2%
Natural gas/oil peaking units 0.1% 0.7% 0.6% 0.2%
Renewables 3.9% 3.5% 3.5% 3.8%
Total company-owned or leased generation units 67.9% 71.2% 72.0% 68.1%
Power purchase contracts:        
Nuclear 25.6% 24.6% 24.5% 25.4%
Natural gas 1.9% 2.4% 1.7% 2.1%
Renewables 2.1% 1.8% 1.1% 2.7%
Other 0.1% —% 0.7% 0.9%
Total power purchase contracts 29.7% 28.8% 28.0% 31.1%
Purchased power from MISO 2.4% —% —% 0.8%
Total purchased power 32.1% 28.8% 28.0% 31.9%
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 four operating plants with a rated capacity of 3,582 MW as of December 31, 2016. 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 2,162 MW as of December 31, 2016. For more information about our operating plants, see Item 2. Properties.

2016 Form 10-K6Wisconsin Electric Power Company
Table of Contents


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, 2016. 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

In order to comply with renewable energy legislation in Wisconsin and Michigan, we meet a portion of our electric generation supply with various renewable energy resources.

Hydroelectric

Our hydroelectric generating system consists of 13 operating plants with both a total installed capacity and a rated capacity of 89 MW as of December 31, 2016. 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, 2016.

Biomass

We have a biomass-fueled power plant at a Rothschild, Wisconsin paper mill site. 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 We Power Units

We also supply electricity to our customers from power plants that we lease from We Power. These plants include the ERGS units and the PWGS 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 We Power 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. In 2008, the PSCW established 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 15.2% reserve margin requirement for the planning year from June 1, 2016, through May 31, 2017. Although MISO's short-term reserve margin changes from year-to-year, fluctuations are typically less than 0.5%. 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 2016 and expect to have adequate capacity to meet the planning reserve margin requirements during 2017.2014:However, extremely hot weather, unexpected equipment failure or unavailability across the 15-state MISO 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.


  Estimate Actual
  2014 2013 2012 2011
Coal 56.0% 53.6% 43.0% 54.2%
Natural Gas - Combined Cycle 6.6% 10.1% 15.9% 6.6%
Renewables 4.1% 3.3% 3.0% 2.0%
Natural Gas/Oil - Peaking Units 0.1% 0.2% 0.7% 0.1%
Net Generation 66.8% 67.2% 62.6% 62.9%
Purchased Power 33.2% 32.8% 37.4% 37.1%
Total 100.0% 100.0% 100.0% 100.0%
2016 Form 10-K7Wisconsin Electric Power Company
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Fuel and Purchased Power Costs

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 rules, see Item 1. Business – D. Regulation.

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

31:
  2013 2012 2011
Coal $27.97
 $30.71
 $29.78
Natural Gas - Combined Cycle $32.22
 $23.62
 $38.02
Natural Gas/Oil - Peaking Units $83.95
 $53.40
 $119.83
Purchased Power $43.74
 $41.92
 $42.79
  2016 2015 2014
Coal $22.68
 $25.25
 $27.68
Natural gas combined cycle 19.13
 23.44
 40.64
Natural gas/oil peaking units 46.99
 56.33
 129.83
Purchased power 43.51
 43.87
 47.47

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 changing domestic and world-wide demand for coal and the impacts of diesel costs, which are incorporated into fuel surcharges on rail transportation.

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

Coal-Fired Generation

Coal Supply:   We diversify the coal supply for our power plants by purchasing coal from mines in Wyoming, Pennsylvania and Montana, as well as from various other states. During 2014, 94% of our projected coal requirements of 10.8 million tons are under contracts which are not tied to 2014 market pricing fluctuations. At the

12Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2013 Form 10-K

end of 2013, our coal-fired generation consisted of six operating plants with a dependable capability of approximately 3,822 MW.

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

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

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

Coal Deliveries:   Approximately 98% of our 2014 coal requirements are expected to be delivered by 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 (PIPP) is transported via rail to Superior, Wisconsin, placed in dock storage and reloaded into lake vessels for plant delivery.

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

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

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

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

Natural Gas-Fired Generation

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

We purchase natural gas for theseour 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 theour plants' variable usage.

We have a PSCW-approved hedging program that allows us to hedge up to 65%75% of our potential risks related to fuel surcharge exposure. We also have a program that allows us to hedge up to 75% of our estimated natural gas usageuse for electric generation in order to help manage our natural gas price risk. These hedging programs are generally implemented on a 36-month forward-looking basis. The results of these programs are reflected in the average costs of this program are included in our fuelnatural gas and purchased power costs.power.

Coal Supply

We diversify the coal supply for our electric generating facilities by purchasing coal from several mines in Wyoming, as well as from various other states. For 2017, approximately 81% of our total projected coal requirements of approximately 10 million tons are contracted under fixed-price contracts. See Note 16, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

The annual tonnage amounts contracted for the next three years are as follows:
(in thousands) Annual Tonnage
2017 7,934
2018 6,120
2019 3,132

Coal Deliveries

All of our 2017 coal requirements are expected 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 may also be used to supplement 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 operates the MISO Energy Markets, which include its bid-based energy markets and ancillary services market. We are a participant in the MISO Energy Markets. For more information on MISO, see Item 1. Business – D. Regulation.

2016 Form 10-K138Wisconsin Electric Power Company
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ITEM 1. BUSINESS - (Cont'd)2013 Form 10-K

Oil-Fired Generation

Fuel oil is used for the combustion turbines at the Germantown Power Plant units 1-4, boiler ignition and flame stabilization at PIPP, and diesel engines at the Pleasant Prairie Power Plant and Valley Power Plant (VAPP). Our oil-fired generation had a dependable capability of approximately 180 MW as of December 31, 2013. Our natural gas-fired peaking units have the ability to burn oil if natural gas is not available due to delivery constraints. Fuel oil requirements are purchased under agreements with suppliers.

Renewable Generation

Hydroelectric:   Our hydroelectric generating system consists of 13 operating plants with a total installed capacity of approximately 88 MW and a dependable capability of approximately 39 MW as of December 31, 2013. Of these plants, 12 plants (86 MW of installed capacity) have long-term licenses from FERC. The other plant, with an installed generating capacity of approximately 2 MW, is operated under a permit granted by another federal agency.

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

Biomass:   We constructed a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site that went into commercial operation on November 8, 2013. Wood waste and wood shavings are used to produce approximately 50 MW of renewable electricity and also support Domtar's sustainable papermaking operations. The final cost of completing this project was $269.0 million, excluding Allowance for Funds Used During Construction (AFUDC).

Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. The following table identifiesAs of December 31, 2016, our power purchase commitments as of December 31, 2013 with unaffiliated parties for the next five years:

Year MW (a)
   
2014 1,267
2015 1,267
2016 1,267
2017 1,267
2018 1,267

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

The above commitments include approximately 1,030years are 1,279 MW per year. This amount includes 1,033 MW per year related to the Point Beacha long-term power purchase agreement. The balance of these purchased power commitments is an arrangement where we buy power at a price determined monthly based on a formula tied to the gas price index.agreement for electricity generated by Point Beach.

Electric Transmission and Energy MarketsOther Matters

American Transmission Company:   ATC is a regional transmission company that owns, maintains, monitorsSeasonality

Our electric utility sales are impacted by seasonal factors and operatesvarying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric transmission systems in Wisconsin, Michigan, Illinoisdistribution system, including substations, transformers, and Minnesota. ATC islines, to meet the demand of our customers. Our generating plants performed as expected to provide comparableduring 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 allnon-firm customers who participate in load management programs.

Competition

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

For more information on competition in energy markets without favoring any market participant. ATC is regulated by FERC for all rate termsour service territories, see Item 7. Management's Discussion and conditionsAnalysis of serviceFinancial Condition and is a transmission-owning memberResults of MISO. MISO maintains operational control of ATC's transmission system, and we are a non-transmission owning member and customer of MISO. We owned approximately 23.0% of ATC as of December 31, 2013 and 2012. For additional information, see Note P -- Related Parties in the Notes to Consolidated Financial Statements.


14Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2013 Form 10-K

In April 2011, ATC and Duke Energy announced the creation of a joint venture, Duke-American Transmission Company, that will build, own and operate new electric transmission infrastructure in North America to address increasing demand for affordable, reliable transmission capacity. DATC has proposed nine new transmission lines, located in five Midwestern states, to support MISO's and PJM Interconnection's transmission expansion plans. These projects are subject to the receipt of all necessary approvals. In addition, in April 2013, DATC acquired a 72% interest in California's Path 15 transmission line.

MISO:   In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which includes the bid-based energy markets and the ancillary services market. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas and Missouri. This new region is referred to as MISO South. We are participants in the Central region. We do not expect these changes to have a material impact on our allocation of MISO costs. For further information on MISO and the MISO Energy Markets, seeOperations – Factors Affecting Results, Liquidity, and Capital Resources --– Industry Restructuring and Competition - Electric Transmission, Capacity and Energy Markets in Item 7.

15Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2013 Form 10-K

Electric Utility Operating StatisticsRestructuring.

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

SELECTED CONSOLIDATED ELECTRIC UTILITY OPERATING DATA
          
Year Ended December 312013 2012 2011 2010 2009
          
Operating Revenues (Millions)         
Residential$1,208.6
 $1,163.9
 $1,159.2
 $1,114.3
 $977.6
Small Commercial/Industrial1,048.0
 1,013.6
 1,006.9
 922.2
 860.3
Large Commercial/Industrial711.9
 744.3
 763.7
 677.1
 599.4
Other - Retail23.4
 22.8
 22.9
 21.9
 21.2
Total Retail Revenues2,991.9
 2,944.6
 2,952.7
 2,735.5
 2,458.5
Wholesale - Other143.7
 144.4
 154.0
 134.6
 116.7
Resale - Utilities143.2
 53.4
 69.5
 40.4
 47.5
Other Operating Revenues28.4
 51.5
 35.1
 25.8
 62.3
Total3,307.2
 3,193.9
 3,211.3
 2,936.3
 2,685.0
Electric Customer Choice (a)1.5
 —
 —
 —
 —
Total Operating Revenues, including customer choice$3,308.7
 $3,193.9
 $3,211.3
 $2,936.3
 $2,685.0
          
MWh Sales (Thousands)         
Residential8,141.9
 8,317.7
 8,278.5
 8,426.3
 7,949.3
Small Commercial/Industrial8,860.4
 8,860.0
 8,795.8
 8,823.3
 8,571.6
Large Commercial/Industrial8,673.4
 9,710.7
 9,992.2
 9,961.5
 9,140.3
Other - Retail152.3
 154.8
 153.6
 155.3
 156.5
Total Retail Sales25,828.0
 27,043.2
 27,220.1
 27,366.4
 25,817.7
Wholesale - Other1,953.5
 1,566.6
 2,024.8
 2,004.6
 1,529.4
Resale - Utilities4,382.7
 1,642.4
 2,065.7
 1,103.8
 1,548.9
Total Electric Sales32,164.2
 30,252.2
 31,310.6
 30,474.8
 28,896.0
Electric Customer Choice (a)813.0
 —
 —
 —
 —
Total MWh Delivered32,977.2
 30,252.2
 31,310.6
 30,474.8
 28,896.0
          
Customers - End of Year (Thousands)         
Residential1,010.5
 1,008.2
 1,005.5
 1,003.6
 1,001.2
Small Commercial/Industrial114.6
 114.3
 113.8
 113.5
 113.1
Large Commercial/Industrial0.7
 0.7
 0.7
 0.7
 0.7
Other2.5
 2.5
 2.5
 2.4
 2.4
Total Customers1,128.3
 1,125.7
 1,122.5
 1,120.2
 1,117.4
          
Customers - Average (Thousands)1,126.9
 1,123.8
 1,121.0
 1,118.7
 1,115.5
          
Degree Days (b)         
Heating (6,580 Normal)7,233
 5,704
 6,633
 6,183
 6,825
Cooling (730 Normal)688
 1,041
 793
 944
 475
For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 16, Commitments and Contingencies.

(a)
Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
(b)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.


16Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2013 Form 10-K

NATURAL GAS UTILITY OPERATIONS

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.


2016 Form 10-K9Wisconsin Electric Power Company
Table of Contents

Natural Gas Utility Operating Statistics

The following table shows certain natural gas utility operating statistics for the past three years:
  Year Ended December 31
  2016 2015 2014
Operating revenues (in millions)
      
Residential $238.6
 $256.6
 $390.5
Commercial and industrial 105.0
 118.9
 204.5
Total retail revenues 343.6
 375.5
 595.0
Transport 13.6
 16.0
 16.8
Other operating revenues * (5.0) 8.2
 2.4
Total $352.2
 $399.7
 $614.2
       
Customers – end of year (in thousands)
      
Residential 442.0
 438.7
 435.6
Commercial and industrial 39.4
 39.1
 38.9
Transport 0.7
 0.7
 0.6
Total customers 482.1
 478.5
 475.1
       
Customers – average (in thousands)
 480.1
 476.4
 472.6

*Includes amounts (refunded to) collected from customers for purchased gas adjustment costs.

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 924.7 million therms during 2013, a 14.3% increase compared with 2012. As of December 31, 2013, we were transporting gas for approximately 550 customers who purchased gas directly from other suppliers.natural gas. Transported natural gas accounted for approximately 35.4%38.0% of the total volumes delivered during 2013, 42.6%2016, 36.4% during 20122015, and 35.1%33.7% during 2011. We had approximately 471,300 and 468,600 gas customers as of December 31, 2013 and 2012, respectively.2014. Our peak daily send-out during 20132016 was 684,860 Dth7.0 million therms on January 21, 2013.18, 2016.

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 paper,governmental, food products, education, metals, and fabricated metal products.real estate.

Natural Gas Deliveries Growth:   We currently forecast totalSales Forecast

Our service territory experienced growth in weather-normalized retail thermnatural gas deliveries (excluding natural gas deliveries for electric generation) in 2016 due to bepositive customer growth, an improving economy, and favorable natural gas prices. We currently forecast retail natural gas delivery volumes to grow at a rate between flat and 0.5% growth over the five-year period ending December 31, 2018, as we expect newnext five years, assuming normal weather. The forecast projects positive customer additions to increase andgrowth being offset an anticipated slight decline in average use per customer. This forecast reflects a current year weather normalized sales level and normal weather.by energy efficiency.

Competition

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

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

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

Natural Gas Supply, Pipeline Capacity and Storage

We have been able to meet our contractual obligations with both our suppliers and our customers. For more information on our natural gas utility supply and transportation contracts, see Note 16, Commitments and Contingencies.

Pipeline Capacity and Storage:   Storage

The interstate pipelines serving Wisconsin originate in major natural 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)2013 Form 10-K

Due to the 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.demand; November through March is considered the winter season. Storage capacity, along with our natural gas purchase contracts, enables

2016 Form 10-K10Wisconsin Electric Power Company
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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 firm daily transportation and storage capacity entitlements from pipelines andwith interstate pipeline companies as well as other service providers under varied-length long-term contracts.

In January 2017, our parent company signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide for some of our storage needs for our natural gas utility operations. We plan to enter into a long-term service agreement to take the allocated storage, subject to PSCW approval and closing of the acquisition. See Note 2, Acquisitions, for more information on this transaction.

Term Natural Gas Supply:   Supply

We have contracts for firm supplies with terms in excess of 30 days3–5 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 9.6 million therms for the 2016 through 2017 heating season.

Secondary Market Transactions:   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,customers, subject to our approved Gas Cost Recovery Mechanism (GCRM).GCRM. During 2013,2016, we continued to participate in the secondary markets. See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 forFor information on the GCRM.our GCRM, see Note 1(d), Revenues and Customer Receivables.

Spot Market Natural Gas Supply:   Supply

We expect to continue to make natural 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 natural gas in the spot gas.market.

Hedging Natural Gas Supply Prices:Prices

We have PSCW approval to hedge (i) up to 60% of planned winter demand and (ii) up to 30%15% of planned summer flowing gas supplydemand using a mix of New York Mercantile Exchange (NYMEX) basedNYMEX-based natural gas options and natural gas futurefutures contracts. Those approvals allowThis approval allows us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payerscustomers 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 basedNYMEX-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 some variations in earnings and working capital throughout the year as a result of changes in weather.


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

Gas Utility Operating Statistics

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

SELECTED CONSOLIDATED GAS UTILITY OPERATING DATA
           
Year Ended December 31 2013 2012 2011 2010 2009
           
Operating Revenues (Millions)          
Residential $296.0
 $250.7
 $304.1
 $310.6
 $365.9
Commercial/Industrial 138.4
 115.4
 149.9
 151.3
 189.7
Interruptible 2.4
 2.3
 2.8
 3.1
 3.5
Total Retail Gas Sales 436.8
 368.4
 456.8
 465.0
 559.1
Transported Gas 16.0
 15.1
 15.0
 14.2
 12.9
Other Operating Revenues (0.9) 1.6
 5.5
 2.4
 (7.8)
Total Operating Revenues $451.9
 $385.1
 $477.3
 $481.6
 $564.2
           
Therms Delivered (Millions)          
Residential 380.8
 294.3
 339.4
 321.8
 349.4
Commercial/Industrial 210.9
 165.3
 198.7
 184.5
 208.8
Interruptible 5.4
 5.0
 5.3
 5.5
 5.9
Total Retail Gas Sales 597.1
 464.6
 543.4
 511.8
 564.1
Transported Gas 327.6
 344.5
 294.4
 300.8
 298.4
Total Therms Delivered 924.7
 809.1
 837.8
 812.6
 862.5
           
Customers - End of Year (Thousands)          
Residential 432.1
 429.6
 427.1
 425.6
 423.8
Commercial/Industrial 38.6
 38.5
 38.5
 38.3
 38.2
Transported Gas 0.6
 0.5
 0.4
 0.4
 0.4
Total Customers 471.3
 468.6
 466.0
 464.3
 462.4
           
Customers - Average (Thousands) 469.7
 466.9
 464.7
 462.9
 460.8
           
Degree Days (a)          
Heating (6,580 Normal) 7,233
 5,704
 6,633
 6,183
 6,825

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


STEAM UTILITY OPERATIONS

Our steam utility generates, distributesworking capital needs are met by cash generated from operations and sells steam supplied bydebt (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 our VAPPwinter natural gas supply needs is typically purchased and Milwaukee County Power Plant.stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. 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 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 alternative fuels. We operate a district steam system in downtown Milwaukeeare allowed to offer lower-priced natural gas sales and transportation services to dual-fuel customers. Under natural gas 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 operating income 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 near south sidesuccess of Milwaukee. Steam is suppliedthird-party natural gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to this system from VAPP, a coal-fired cogeneration facility. We also operate the steam productionother sources and distribution facilities of the Milwaukee County Power Plant located on the Milwaukee County Grounds in Wauwatosa, Wisconsin.arranging or facilitating competitively priced transportation service for those customers that desire to buy their own natural gas supplies.

Annual sales of steam fluctuate from yearFederal and state regulators continue to year based upon system growth and variations in weather conditions. During 2013,implement policies to bring more competition to the steamnatural gas industry. While the natural gas utility had $39.6 million of operating revenues fromdistribution function is expected to remain a highly regulated, monopoly function, the sale of 2,750 million poundsthe natural gas commodity and related services are expected to remain subject to competition from third parties for large commercial and industrial customers.

C. OTHER SEGMENT

At December 31, 2016, our other segment included Bostco, our non-utility subsidiary, that develops and invests in real estate, as well as equity earnings from our investment in ATC.

American Transmission Company 

ATC is a regional transmission company that owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Minnesota. ATC is expected to provide comparable service to all customers, including us, and to support effective competition in energy markets without favoring any market participant. ATC is regulated by the FERC for all rate terms and conditions of steam compared with $34.3 millionservice and is a transmission-owning member of operating revenues from the saleMISO. MISO maintains operational control of 2,449 million poundsATC's transmission system, and we are a non-transmission owning member and customer of steam during 2012.MISO. As of December 31, 2013 and 2012, steam2016, our ownership interest in ATC was approximately 23%; however, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information.

ATC is currently named in a complaint filed with the FERC requesting a reduction in the base ROE used by approximately 445 customersMISO transmission owners. See Item 7. Management's Discussion and 460 customers, respectively,Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints, for processing, space heating, domestic hot watermore information.

D. REGULATION

As of December 31, 2016, we were subject to the requirements of the Public Utility Holding Company Act of 2005 (PUHCA 2005) as we met the definition of a holding company under this Act due to our ownership interest in ATC. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information. As a result, we are no longer subject to the requirements of PUHCA 2005.

In addition to the specific regulations noted below, we are also subject to regulations, where applicable, of the EPA, the WDNR, the MDEQ, the Michigan Department of Natural Resources, and humidification.the United States Army Corps of Engineers.


2016 Form 10-K1912Wisconsin Electric Power Company
Table of Contents

Rates
Our rates are regulated by the various commissions shown in the table below. These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.
Regulated RatesRegulatory Commission
Retail electric, natural gas, and steamPSCW
Retail electricMPSC *
Wholesale powerFERC

*Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden Mining Company. See Note 4, Related Parties, and Note 20, Regulatory Environment, for additional information.

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 were recovered dollar-for-dollar from our Michigan retail electric customers and our Wisconsin wholesale electric customers. Our natural gas utility operates 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 are subject to an earnings sharing mechanism for three years beginning January 1, 2016. See Note 2, Acquisitions, for more information on this earnings sharing mechanism.

For information on how our rates are set, see Note 20, 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:
  2016 2015 2014
(in millions) Amount Percent Amount Percent Amount Percent
Electric            
Wisconsin $2,973.3
 86.4% $2,961.9
 85.7% $2,990.4
 86.8%
Michigan 154.2
 4.5% 163.0
 4.7% 58.8
 1.7%
FERC – Wholesale 313.1
 9.1% 329.5
 9.6% 396.0
 11.5%
Total 3,440.6
 100.0% 3,454.4

100.0% 3,445.2
 100.0%
             
Natural Gas – Wisconsin 352.2
 100.0% 399.7
 100.0% 614.2
 100.0%
             
Total utility operating revenues $3,792.8
 

 $3,854.1
 

 $4,059.4
 


ITEM 1. BUSINESS - (Cont'd)20132016 Form 10-K13Wisconsin Electric Power Company


Table of Contents
UTILITY RATE MATTERS

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


REGULATIONElectric Transmission, Capacity, and Energy Markets

WeIn 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 enhanced the energy market by including an ancillary services market. 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, and has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

In MISO, base transmission costs are a holding company becausecurrently being paid by load-serving entities located in the service territories of our ownership interest in ATC, but are exempt fromeach MISO transmission owner. The FERC has previously confirmed the requirementsuse of the Public Utility Holding Company Actcurrent transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.

As part of 2005.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 hedge transmission congestion costs through ARRs and FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2016, through May 31, 2017. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

Beginning June 1, 2013, MISO instituted an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources could be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. Our capacity requirements during 2016 were fulfilled using our own capacity resources.

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, gasAct 141 in Wisconsin and steam ratesPublic Acts 295 and 342 in the state of Wisconsin, standards of service, issuance of securities, construction ofMichigan, which contain certain new facilities, transactions with affiliates, billing practicesminimum requirements for renewable energy generation. See Note 16, Commitments and various other matters. We are also subject to the regulation of the PSCW as to certain levels of short-term debt obligations. We are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state of Michigan, except as to the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Almost allContingencies, for more information.

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

Other Natural Gas Regulations

Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by FERC. Wethe FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the state commissions are subject to the regulation of FERC with respect to wholesale power service, electric reliabilityresponsible for monitoring and enforcing requirements and accounting and with respect togoverning our participation in the interstate natural gas pipeline capacity market. For information on how rates are set, see Ratessafety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 49 Code of Federal Regulations (CFR) Part 191 (Transportation of Natural and Regulatory Matters under Factors Affecting Results, LiquidityOther Gas by Pipeline; Annual Reports, Incident Reports, and Capital Resources in Item 7.Safety-Related Condition Reports), 49 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).

The following table comparesWe are required to provide natural gas service and grant credit (with applicable deposit requirements) to customers within our operating revenues by regulatory jurisdictionservice 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 that provide for eacha limited amount of the three years in the period ended December 31, 2013:funding for assistance to our low-income customers.

  2013 2012 2011
  Amount Percent Amount Percent Amount Percent
  (Millions of Dollars)
Electric            
Wisconsin - Retail $2,874.8
 86.9% $2,808.4
 87.9% $2,775.8
 86.4%
Michigan - Retail 147.0
 4.4% 187.8
 5.9% 212.0
 6.6%
FERC - Wholesale 286.9
 8.7% 197.7
 6.2% 223.5
 7.0%
Total 3,308.7
 100.0% 3,193.9
 100.0% 3,211.3
 100.0%
             
Gas - Wisconsin - Retail 451.9
 100.0% 385.1
 100.0% 477.3
 100.0%
             
Steam - Wisconsin - Retail 39.6
 100.0% 34.3
 100.0% 39.0
 100.0%
Total Utility Operating Revenues $3,800.2
 

 $3,613.3
 

 $3,727.6
 


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

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

Public Benefits and Renewable Portfolio Standard

2005 Wisconsin Act 141 (Act 141) established a goal that 10% of electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we must meet certain minimum requirements for

2016 Form 10-K2014Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2013 Form 10-K

renewable energy generation. For the years 2010 through 2014, we must increase our percentageTable of total retail energy sales provided by renewable sources (renewable energy percentage) by at least two percentage points from our baseline renewable percentage of 2.27%. As of December 31, 2013, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. In addition, under this Act, 1.2% of utilities' annual operating revenues were required to be used to fund energy conservation programs in 2013. The funding required by Act 141 for 2014 is also 1.2% of annual operating revenues.Contents

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

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


E. 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 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources --– Capital Requirements in Item 7. For discussion of additional environmental issues, see Environmental Matters in Item 3. For further information concerning air and water quality standards and rulemaking initiated by the EPA, including estimated costs of compliance, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7.Requirements. 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 Q --16, Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.Contingencies.

Compliance with federal, state and local environmental protection requirements resulted in capital expenditures of approximately $24.7 million in 2013 compared with $64.1 million in 2012. Expenditures incurred during 2013 and 2012 primarily included costs associated with the installation of pollution abatement facilities at our power plants. These expenditures are expected to be approximately $2.3 million during 2014. Operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $92.9 million and $82.6 million during 2013 and 2012, respectively.
F. EMPLOYEES

Coal Combustion Product Fills and Landfills

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

Oak Creek Site Landfills:   Groundwater near the sites, located in the Village of Caledonia and the City of Oak Creek, Wisconsin, was found to contain levels of molybdenum above the allowable limit prompting us to begin investigation in 2009 for the source of the molybdenum. Our study indicates that the groundwater impacts are naturally occurring or are from other sources based on groundwater flow direction and increasing concentrations of elements deeper in the ground. The WDNR began sampling work in 2011 to identify the source of the groundwater impacts and issued its report in 2013. The WDNR study found that the data was inconclusive as to the source

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

causing the groundwater impacts. We reviewed the WDNR report and provided technical comments further supporting our position that regional ground water impacts are not a result of coal ash management activities at the Oak Creek site. The Wisconsin Department of Health Services has since increased the allowable limit for molybdenum in groundwater, and the WDNR sent a letter to residents with private wells that exceeded the earlier limit with information about the change.


OTHER

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

Employees:As of December 31, 2013,2016, we had 3,893 total3,099 employees, of which 2,5173,021 were full-time.

As of December 31, 2016, 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 1,7301,667
 August 15, 2017
Local 420 of International Union of Operating Engineers, AFL-CIO 539458
 September 30, 2017
Local 2006 Unit 1 of United Steel Workers of America, AFL-CIO 142119
 April 30, 2017
Local 510 of International Brotherhood of Electrical Workers, AFL-CIO 106
 October 31, 20162020
Total 2,5172,350
  



2016 Form 10-K2215Wisconsin Electric Power Company
Table of Contents
2013 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 Legislation and Regulation

Our business is significantly impacted by governmental regulation.

We are subject to significant state, local, and federal governmental regulation. We are subject toregulation, including regulation by the PSCW, MPSC, and the 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 regulation by the MPSC of various matters associated with retail electric service in the state of Michigan, except the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Further, our hydroelectric facilities are regulated by FERC, and FERC also regulates ourcustomers; wholesale power service practices,practices; electric reliability requirements and accounting, andaccounting; 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.

The rates we are allowed to charge our customers for electric, natural gasretail and steamwholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Within our utility operations, approximately 87% of our 2013 electric revenues were regulated by the PSCW, 4% were regulated by the MPSC and the balance of our electric revenues were regulated by the FERC. All of our natural gas and steam revenues are regulated by the PSCW. Rate regulation is based on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent on regulatory action, and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable return on equity.ROE. We defer certain costs and revenues as regulatory assets and liabilities for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured, and is subject to review and approval by our regulators. If recovery of regulatory assets is not approved or is no longer deemed probable, these costs would be charged to incomerecognized in the current period expense and could have a material adverse impact on our results of operations, cash flows, and financial results.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

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

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

We may face significant costs of complianceto comply with existing and future environmental laws and regulations.

Our operations are subject to extensivenumerous federal and state environmental legislationlaws and regulation by stateregulations. These laws and federal environmental agencies governing,regulations govern, among other things, air emissions such as Carbon Dioxide (CO(including CO2, methane, mercury, SO2), Sulfur Dioxide (SO2)and NOx), Nitrogen Oxide (NOx), fine particulates and mercury; water discharges;quality, wastewater discharges, and management of hazardous, toxic, and solid wastes and substances. We incur significant expenditures in complyingcosts to comply with these environmental requirements, including expenditures forcosts associated with the installation of pollution control equipment, environmental monitoring, emissions fees, and permits at all of our facilities.

The EPA has adopted and is in the process of implementing regulations governing the emission of NOx, SO2, fine particulate matter (PM2.5), mercury and other air pollutants under the Clean Air Act (CAA) through the National Ambient Air Quality Standards (NAAQS), the Mercury and Air Toxics Standards (MATS) rule and other air quality regulations. In addition, the EPA has proposed rules governing cooling water intake structures at our power plants and revisions to the effluent guidelines for steam electric generating plants under the Clean Water Act (CWA). The EPA also adopted the Cross-State Air Pollution Rule (CSAPR), which provides for limits on the interstate transport of NOx and SO2 emissions. The U.S. Court of Appeals for the D.C. Circuit vacated the CSAPR; however, the EPA successfully petitioned the United States Supreme Court, who heard the case in December 2013. A decision is expected by June 2014. Therefore, there is still substantial uncertainty as to what capital expenditures may ultimately be required to comply with these regulations.

We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. We expect that additional environmental controls will be required at PIPP to meet the new environmental standards, and are currently analyzing several environmental compliance options.

In addition, we announced plans to convert the fuel source for VAPP from coal to natural gas. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC. These and other compliance costs we expect to incur over the next three years are included in the table under "Capital Expenditures" in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations.

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

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

The WDNR has issued a NoticeEPA adopted and implemented (or is in the process of Violation (NOV) to us alleging violationsimplementing) regulations governing the emission of certain environmental rulesNOx, SO2, fine particulate matter, mercury, and other air pollutants under the Clean Air Act through the NAAQS, the MATS rule, the Clean Power Plan, the CSAPR, and other air quality regulations. In addition, the EPA finalized regulations under the Clean Water Act that govern

2016 Form 10-K16Wisconsin Electric Power Company
Table of Contents

cooling water intake structures at our Paris Generating Station (PSGS). An adverse outcomepower 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 matters could requireand other environmental regulations. In addition, as a result of the new Federal Executive Administration taking office in January 2017 and other factors, there is uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with existing and future environmental laws and regulations.

Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level that cannot be determined at this timecould result in significant additional expenditures for our generation units or distribution systems, including, without limitation, costs to further limit GHG emissions from our operations; 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 possibly require paymentaffect the availability and/or cost of penalties.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, 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.

Our electricLitigation over environmental issues and gas utility businesses are also subject to significant liabilities related to the investigationclaims of various types, including property damage, personal injury, common law nuisance, and remediationcitizen enforcement of environmental contamination at certain oflaws and regulations, has increased generally throughout the United States. 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 and former facilities, and at third-party owned sites. Due to the potential for imposition of stricter standards and greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate.

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

Wewe 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 thethese facilities. If we fail (or failed) to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.

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

The regulation of greenhouse gas emissions continuesFederal, state, regional, and international authorities have undertaken efforts to be a top priority for the President's administration.limit GHG emissions. In June 2013, the President issued a presidential memorandum instructing2015, the EPA to, among other things, issue rules pertaining to greenhouse gasissued the Clean Power Plan, which is a final rule that regulates GHG emissions from bothexisting 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. With the January 2017 change in the Federal Executive Administration, the legal and existing plants.regulatory future of federal GHG regulations, including the Clean Power Plan, faces increased uncertainty. We are continuing to analyze the GHG emission profile of our electric generation resources and to work with other stakeholders to determine the potential impacts to our operations by the implementation of the Clean Power Plan, any successor rule, and federal GHG regulations in general. In October 2015, numerous states (including Wisconsin and Michigan), trade

In June 2012,
2016 Form 10-K17Wisconsin Electric Power Company
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associations, and private parties filed lawsuits challenging the U.S.Clean Power Plan, 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 fordenied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the Clean Power Plan rules until disposition of the litigation in the D.C. Circuit upheldCourt of Appeals and to the EPA's authorityextent that further appellate review is sought, at the Supreme Court. In addition, in February 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 Clean Power Plan or its successor is not expected to regulate greenhouse gas emissions. The EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. In September 2013, the EPA withdrew its 2012 proposed New Source Performance Standards greenhouse gas emissions rule, and issued new proposed rules with greenhouse gas limits for new fossil fueled power plants. The rule would not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines. Based upon currently available technology and the emission limitsresult in the proposed rule, we believe that this rule, if promulgated, would effectively prohibit new conventional coal-fired power plants.

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

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

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

There is no guarantee that we will be allowed to fully recover costs incurred to comply with any legislation, regulationthe Clean Power Plan or order that requires a reduction in greenhouse gas emissionsother federal regulations, or that cost recovery will not be delayed or otherwise conditioned. Any legislation or regulationThe Clean Power Plan and any other related regulations that may be adopted in the future, at either at the federal or state level, may cause our environmental compliance spending to reduce greenhouse gas emissions could have a material adverse impact on our electric generationdiffer materially from the amounts currently estimated. In December 2016, Michigan enacted Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement to 12.5% for years 2019 through 2020, and natural gas distribution operations. Such regulationincreases the requirement to 15.0% for 2021. These regulations, as well as changes in the fuel markets and advances in technology, could make some of our electric generating units uneconomic to maintain or operate, and could affect unit retirement and replacement decisions. These regulations could also adversely affect our future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates.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. 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 regulation of 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 may face significant costs if coal combustion products are regulated as hazardous waste.be negatively impacted by changes in federal income tax policy.

We are impacted by United States federal income tax policy. Both the new Federal Executive Administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes to corporate income tax laws. These proposed changes include, among other things, a reduction in the corporate income tax rate, the immediate deductibility of 100% of capital expenditures, and the elimination of the interest expense deduction. We are currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizescumulative positive or negative impact on us. However, it is possible that changes in 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, itUnited States federal income tax laws could have a materialan adverse effect on our ability to continueresults of operations, financial condition, and liquidity. For example, the immediate deductibility of capital expenditures could have the effect of reducing growth in 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,regulated rate base, which could adverselynegatively impact our results of operations and financial condition. We anticipate that the EPA could take action on this matter by the end of 2014.

operations.
25Wisconsin Electric Power Company

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

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

Energy conservation and rate increases could negatively impact financial results.

Customers could voluntarily reduce their consumption of electricity, natural gas and steam in response to decreases in their disposable income, increases in energy prices and/or individual conservation efforts. In addition, Wisconsin and Michigan have adopted energy efficiency targets to reduce energy consumption by certain dates. To the extent there is any regulatory lag to adjust rates as a result of reduced sales from effective conservation measures, these measures could have a negative impact on our results of operations and cash flows.

In addition, any higher costs that are collected through rates could contribute to reduced demand for electricity, natural gas or steam, which could adversely impact our results of operations and financial condition.

Risks Related to the Operation of Our Business

Our financial performance may be adversely affected if weoperations are unablesubject to successfully operaterisks arising from the reliability of our facilities.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 generatinggeneration and natural gas and electric distribution facilities. OperationThe operation of these facilities involves many risks, including:including operator error and the breakdown or failure of equipment processes;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 interruptions;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

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environmental or other regulatory requirements; terrorist attacks; or cyber security threats; or catastrophicintrusions. Any of these events such as fires, earthquakes, explosions, floods or other similar occurrences.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 canat our power plants may reduce our revenues or cause us to incur significant costs if 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 regulatory process may not cover any or all of these lost revenues or increased expenses, as well as incremental replacement power costs. A decrease in revenues from these facilities or an increase in operating costswhich could adversely affect our results of operations and cash flows.

CustomerOur operations are subject to various conditions that can result in fluctuations in energy sales to customers, including customer growth and general 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 negativelymay result in lower revenues and net income.
Our customers' continued focus on energy conservation and ability to meet their own energy needs. Our customers' use of electricity has decreased as a result of individual conservation efforts, including the use of more energy efficient technologies. These conservation efforts could continue. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income and increases in energy prices. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. In addition, several states, including Wisconsin, have adopted energy efficiency targets to reduce energy consumption by certain dates.

As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact theour results of operations and cash flows of our electric utility business. In addition, mild temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.financial condition.


26Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2013 Form 10-K

Factors beyond our controlWe 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.

We expectOur business requires substantial capital expenditures for investments in, among other things, capital improvements to spend an aggregateour electric generating facilities, electric and natural gas distribution infrastructure, and other projects, including projects for environmental compliance.

Achieving the intended benefits of between $2.3 billion and $2.4 billion during the period 2014 to 2018 on capital investments. These types ofany large construction projects areproject is subject to many uncertainties, some of the usual construction risks over which we will have limited or no control and which mightover, that could adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the ability to obtain oradhere to established budgets and time frames; the costavailability of labor or materials;materials at estimated costs; the ability of the contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable lawlaws or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy.

Certain In addition, certain of these projects require the approval of our regulators. InIf construction of commission-approved projects should materially and adversely deviate from the event we receiveschedules, estimates, and projections on which the approval total costs of a project may be higher than estimated and/or higher than amounts approved bywas based, our regulators may deem the additional capital costs as imprudent and there is no guarantee that we will be allowed to recover these additional costs indisallow recovery of them through rates.

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

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

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

In addition, damages resulting from severe weather events within our service territoriesfinancial condition may result in the loss of customers and reduced demand for electricity and natural gas for extended periods. Any significant loss of customers or reduction in demand couldbe adversely affect our results of operations and cash flows.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 legislation or regulations could be adopted supporting the use of these technologies. There is also a risk that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station power electric production. If these technologies becamebecome cost competitive and achievedachieve economies of scale, our market share could be eroded, and the value of our generating facilities could be reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.

UnderOur operations are subject to risks beyond our current rate structure, widespread adoptioncontrol, including but not limited to, cyber security intrusions, terrorist attacks, acts of distributed generation by our electric customers could increase the cost of service for our remaining customers. Increases in our rates could contributewar, or unauthorized access to slower than anticipated customer growth and reduced demand for electricity, which could have an adverse impact on our financial condition, results of operations and cash flows.personally identifiable information.

We could beface the subjectrisk of terrorist attacks and cyber intrusions, that disruptboth threatened and actual, against our generation facilities, electric generation and natural gas distribution operations and/or result in security breaches that expose us to a risk of loss or misuse of confidentialinfrastructure, our information and proprietary information, litigation and potential liability.

We operate in an industry that requires the continued operation of sophisticated information technology systems, and network infrastructure, which are part of an interconnected regional transmission grid. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees.


27Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2013 Form 10-K

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

In addition, any theft, loss and/or fraudulent use of customer, stockholder, employee or proprietary data as a result of cyber intrusion or otherwise could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers, stockholders and regulators, among others. At this time, we are not aware of any cyber intrusion or security breach of our systems.

Internet-based attacks on critical U.S. energy infrastructure are occurring with more frequency. In February 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 being developed jointly by the government and industry.

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

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

Our electric generation and gas distribution facilities, including the facilitiesthat 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.cash flows.

FailureWe operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful cyber security intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission and distribution systems, could disrupt our operations and result in loss of service to customers. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant costs if 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. 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 security intrusions. If our assets or systems were to fail, be physically damaged, or be breached and were not recovered in a timely 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 confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers and regulators, among others. 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. We may also need to obtain additional insurance coverage related to the threat of such intrusions.

The costs of repairing damage to our facilities, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.


2016 Form 10-K20Wisconsin Electric Power Company
Table of Contents

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

Inherent in natural gas distribution activities are a 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 employees and non-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 level of damages resulting from these risks. These activities may subject us to litigation or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms.

We may fail 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 unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. 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.

Failure of a counterpartyour counterparties to one of ourmeet their obligations, including obligations under power purchase agreements, could 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. Currently, sales through power purchase agreements are responsible for approximately 4.5% of our electric revenues. Revenues are dependent on the continued performance by the purchasers of their obligations under the power purchase agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more purchasers could fail to perform their obligations under the power purchase agreements. If this were to occur, we would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase agreement would be reallocated among our retail customers.customers. To the extent there is any regulatory lag to adjustdelay in adjusting rates, a customer default under a power purchase agreement could have a negative impact on our results of operations and cash flows.

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, including us, can continue to be integrated in an efficient, effective, and timely manner.

It is possible that the remaining integration efforts could take longer and be more costly 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. 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.


2016 Form 10-K2821Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2013 Form 10-K

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 integrationTable 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.Contents

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-termcredit 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.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, underon 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

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

A rating downgrade, andowngrade;
An economic downturn or uncertainty, prevailinguncertainty;
Prevailing market conditions concernsand rules;
Concerns over foreign economic conditions and/or the ability of foreign governments and central banks to respond to changing economic conditions, changesconditions;
Changes in tax policy, warpolicy;
War or the threat of war, a negativewar; and
The overall health and view of the utility industry, failuresand financial institution industries.

If any of financial institutionsthese risks or other factors,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, could be limited which, in turn, could materially and adversely affect our results of operations.

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

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

Our service territories have been impacted by the slow economy the country has been experiencing over the past several years. As a result, we expect to continue experiencing electric sales below historical trends.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, without limitation,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 the industryus or the Companyutility industry has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings. If we are downgraded

Any downgrade by the rating agencies ourcould:

Increase borrowing costs could increase,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 could decreaseby limiting our access to the commercial paper market;
Limit the availability of adequate credit support for our operations; and for any downgrade to below investment grade,
Trigger collateral requirements may be triggered in severalvarious contracts.


29Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2013 Form 10-K

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

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

Michigan has adopted retail choice. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. The two iron ore mines are excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.
The mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers have switched to an alternative electric supplier. Sales to these customers, including the mines, totaled 2,173.6 GWh, or 7.6% of our retail electric sales for the year ended December 31, 2012. Previously, the owner of the mines announced that they would shut down the Empire mine by the end of 2014 or beginning of 2015. We negotiated an SSR agreement with MISO and took other steps to mitigate the loss of these sales. Although the financial impact in future periods is uncertain, we currently estimate that these losses will not have a material impact on our consolidated financial statements in 2014.

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

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

An increase in natural gas costsFluctuating commodity prices could negatively impact our electric and natural gas utility operations.

Our operating 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 peaking powerelectric generation plants, and in Port Washington Generating Station Unit 1 (PWGS 1) and Port Washington Generating Station Unit 2 (PWGS 2), and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. DisruptionThe cost of natural gas may increase because of disruptions 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, andthe demand for natural gas. Higher natural gas, costs can haveand the effectavailability of increasing demand for other sources of fuel thereby increasing the costs of those fuels as well. Additionally, high naturalshale gas costs increase our working capital requirements and could adversely impact our collections of accounts receivable.potential regulations affecting its accessibility.

For Wisconsin retail electric customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical two percent2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Our natural gas distribution business receives dollar for dollaroperations receive dollar-for-dollar recovery of prudently incurred natural gas costs.


2016 Form 10-K22Wisconsin Electric Power Company
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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 lower revenues, 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 revenues and operating expenses; and
Shutting down of generation facilities if the cost of natural gas, subject to tolerance bands and prudency review.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.facilities and engage in opportunity sales.

We are dependent on coal for much of our electric generating capacity. Although we generally carry sufficient coal inventory at our generating facilities to mitigateprotect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate to fully mitigate all potential reductions in supply.adequate. While we have coal supply and transportation contracts in place, there can be no assurancewe 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

30Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2013 Form 10-K

their ability to fulfill their obligations to us, or we may experience operational problems or constraints that prevent us from taking delivery. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Furthermore, demand for coal can impact its availability and cost. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our coalcoal-fired units and replace this lost generation through additional power purchases in the MISO market.Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates.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 market.Energy Markets. If we do not have an adequate supply of coal for our coal-fired units or 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.

PoorRestructuring in the regulated energy industry and competition in the retail and wholesale markets could have a negative impact on our business and revenues.

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.

The FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. The MISO Energy Markets rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes 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 market for operating reserves that schedules energy and ancillary services at the same time as part of the energy market, allowing for more efficient use of generation assets in the MISO market. These market designs continue to have the potential to increase the costs of transmission, the costs associated with

2016 Form 10-K23Wisconsin Electric Power Company
Table of Contents

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

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.

We may experience poor investment performance of benefit plan holdings due to changes in assumptions and other factors impactingmarket conditions.

We have significant obligations related to pension and OPEB plans. If WEC Energy Group is unable to successfully manage benefit plan assets and our medical costs, could unfavorably impact our liquidity andcash flows, financial condition, or results of operations.operations could be adversely impacted.

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 may increase our funding requirements. Changes in interest rates affect plan liabilities - as rates decrease, the liabilities increase, which could increase our funding requirements. Changes in demographics, such as an increase in the number of retirements or changes in life expectancy assumptions, may also increase our funding requirements. Changes made to the plans may also impact current and future pension costs. We are facing risingIn addition, medical costs for both active and retired employees. It is possible that these costsemployees 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. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.


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

None.


2016 Form 10-K3124Wisconsin Electric Power Company
Table of Contents
2013 Form 10-K


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 PTFERGS and PWGS generating units.units from We Power.

As of December 31, 2013,2016, we owned, or leased from We Power, the following generating assets:

    No. of Dependable
    Generating Capability
Name Fuel Units In MW (a)
Coal-Fired Plants      
South Oak Creek Coal 4
 990
Oak Creek Expansion Coal 2
 1,057
Presque Isle Coal 5
 344
Pleasant Prairie Coal 2
 1,188
Valley Coal 2
 236
Milwaukee County Coal 3
 7
Total Coal-Fired Plants   18
 3,822
Natural Gas-Fired Plants      
Port Washington Generating Station Gas 2
 1,082
Germantown Combustion Turbines Gas/Oil 5
 258
Concord Combustion Turbines Gas/Oil 4
 352
Paris Combustion Turbines Gas/Oil 4
 352
Other Combustion Turbines & Diesel Gas/Oil 2
 —
Total Natural Gas-Fired Plants   17
 2,044
Renewables      
Hydro Plants (13 in number)   33
 39
Rothschild Biomass Plant Biomass 1
 50
Byron Wind Turbines Wind 2
 —
Blue Sky Green Field Wind 88
 29
Glacier Hills Wind 90
 32
Montfort Wind Energy Center Wind 20
 5
Total Renewables   234
 155
Total System   269
 6,021
Name Location Fuel Number of Generating Units 
Rated Capacity In MW (1)
 
Coal-fired plants         
ERGS Oak Creek, WI Coal 2
 1,057
(2) 
Pleasant Prairie Pleasant Prairie, WI Coal 2
 1,188
(3) 
PIPP Marquette, MI Coal 5
 344
 
OCPP Oak Creek, WI Coal 4
 993
 
Total coal-fired plants     13
 3,582
 
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
 
PWGS Port Washington, WI Natural Gas 2
 1,140
 
VAPP Milwaukee, WI Natural Gas 2
 240
 
Total natural gas-fired plants     17
 2,342
 
Renewables         
Hydro Plants (13 in number) WI and MI Hydro 30
 89
 
Rothschild Biomass Plant Rothschild, WI Biomass 1
 50
 
Blue Sky Green Field Fond du Lac, WI Wind 88
 21
 
Byron Wind Turbines Fond du Lac, WI Wind 2
 —
 
Glacier Hills Cambria, WI Wind 90
 28
 
Montfort Wind Energy Center Montfort, WI Wind 20
 2
 
Total renewables     231
 190
 
Total system     261
 6,114
 

(a)
(1)
Dependable capabilityBased on expected capacity ratings for summer 2017, 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 state of repair as of a given month in a given year.the summer months, primarily due to air conditioning demand.

(2)
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 year to year. Dependable capabilitycapacity indicated for the wind sitesfacility is determinedequal to We Power's portion of total plant capacity based on a capacity factorits 83.34% ownership.

(3)
Starting in 2017, Pleasant Prairie Power Plant will be placed into economic reserve during months of approximately 20%.traditionally lower electric demand. From March through May and from September through November, the units will be on economic reserve.

As of December 31, 2013,2016, we operated approximately 21,51121,500 pole-miles of overhead distribution lines and 24,08624,800 miles of underground distribution cable, as well as approximately 350355 distribution substations and 290,999approximately 301,700 line transformers.

As of December 31, 2013,2016, our natural gas distribution system included approximately 9,51410,200 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 410,000 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.


32Wisconsin Electric Power Company
ITEM 2. PROPERTIES - (Cont'd)2013 Form 10-K

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

2016 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, 2013,2016, the combined steam systemssystem supplied by the VAPP and Milwaukee County Power Plant consisted of approximately 4240 miles of both high pressure and low pressure steam piping, nineapproximately four miles of walkable tunnels and other pressure regulating equipment.

General

Effective January 1, 2017, we transferred our electric distribution lines located in Michigan to UMERC, a new stand-alone utility in the Upper Peninsula of Michigan owned by WEC Energy Group. See Note 4, Related Parties, and Note 20, Regulatory Environment, for more information about the new utility.

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.

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

Solvay Coke and Gas Site:  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 Q --16, Commitments and Contingencies, in the Notes to Consolidated Financial Statements.

Edgewater Generating Unit 5:In December 2009, the EPA issued a NOV concerning several coal-fired power plants owned and operated by Wisconsin PowerNote 20, Regulatory Environment, for additional information on material legal proceedings and Light Company (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. Although we sold our interest to WPL in March 2011, we retained our share of the liability related to the NOV.

In April 2013, a complaint and consent decree were simultaneously lodged with the court in United States v. Wisconsin Power and Light Company, Madison Gas and Electric Company, Wisconsin Electric Power Company and Wisconsin Public Service Corporation, Case No. 13-cv-00266. The consent decree was entered by the court in June 2013, and resolved all allegations in the NOV related to Edgewater 5 and the other coal fired power plants owned and operated by WPL, as well as air permitting and opacity violations alleged by Sierra Club against WPL. Our share of the financial obligation associated with this consent decree was immaterial. This matter was fully closed when the consent decree was terminated as to us on October 1, 2013.
See Environmental Compliance in Item 1 and Environmental Matters, Manufactured Gas Plant Sites, and Coal Combustion Product Landfill Sites in Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements which are incorporated by reference herein, for a discussion of matters related to certain solid wasteus and coal combustion product landfills, manufactured gas plant sites and air quality.



33Wisconsin Electric Power Company
ITEM 3. LEGAL PROCEEDINGS - (Cont'd)2013 Form 10-K

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

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


ITEM 4.MINE SAFETY DISCLOSURES
ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.



2016 Form 10-K3426Wisconsin Electric Power Company
Table of Contents
2013 Form 10-K


EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, at December 31, 2013 and positions of our executive officers at December 31, 2016 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.   Allen L. Leverett.Age 63.50.
WisconsinWEC Energy -- Chairman of the Board andGroup — Chief Executive Officer since May 2004. President from April 2003 to July 2013.
Wisconsin Electric -- Chairman of the Board2016. Director since May 2004. President and Chief Executive Officer since August 2003.
Wisconsin Gas -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
Director of Joy Global, Inc. and Badger Meter, Inc.
Director of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas since 2003.

Stephen P. Dickson.   Age 53.
Wisconsin Energy -- Vice President since 2005. Controller since 2000.
Wisconsin Electric -- Vice President since 2005. Controller since 2000.
Wisconsin Gas -- Vice President since 2005. Controller since 1998.

J. Kevin Fletcher.   Age 55.
Wisconsin Electric -- Senior Vice President since October 2011.
Wisconsin Gas -- Senior Vice President since October 2011.
Georgia Power -- Vice President - Community and Economic Development from 2007 to October 2011. Georgia Power is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.

Robert M. Garvin.   Age 47.
Wisconsin Energy -- Senior Vice President since April 2011.
Wisconsin Electric -- Senior Vice President since April 2011.
Wisconsin Gas -- Senior Vice President since April 2011.
American Transmission Co. -- Vice President and General Counsel from 2009 to April 2011.
NextEra Energy Resources -- Vice President from 2007 to 2009.

J. Patrick Keyes.   Age 48.
Wisconsin Energy -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to February 2013. Vice President from April 2011 to August 2012.
Wisconsin Electric -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to February 2013. Vice President from April 2011 to August 2012.
Wisconsin Gas -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to February 2013. Vice President from April 2011 to August 2012.
Accenture -- Senior Executive from September 2001 to March 2011.

Allen L. Leverett.   Age 47.
Wisconsin Energy --January 2016. President since August 2013. Executive Vice President from May 2004 to July 2013. Chief Financial Officer from July 2003 to February 2011.
Wisconsin Electric --WE — Chairman of the Board and Chief Executive Officer since May 2016. Director since June 2015. President from June 2015 to May 2016. 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.

J. Kevin Fletcher.   Age 58.
WE — President since May 2016. Director since June 2015. Executive Vice President - Customer Service and Operations from June 2015 to April 2016. Senior Vice President - Customer Operations from October 2011 to June 2015.

Robert M. Garvin.   Age 50.
WEC Energy Group — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.
WE — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.

William J. Guc.   Age 47.
WEC Energy Group — Controller since October 2015. Vice President since June 2015.
WE — Vice President and Controller since October 2015.
Integrys Energy Group — Vice President and Treasurer from December 2010 to June 2015.

Scott J. Lauber.   Age 51.
WEC Energy Group — Executive Vice President and Chief Financial Officer since April 2016. Vice President and Treasurer from February 2013 to March 2016. Assistant Treasurer from March 2011 to January 2013.
WE — Director and Executive Vice President and Chief Financial Officer since April 2016. Vice President and Treasurer from February 2013 to March 2016. Assistant Treasurer from March 2011 to January 2013.

Susan H. Martin.   Age 61.64.
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.

35Wisconsin Electric Power Company
EXECUTIVE OFFICERS OF THE REGISTRANT - (Cont'd)2013 Form 10-K

Wisconsin Electric -- Executive Vice President and General CounselWE — 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.

Tom Metcalfe.   Age 49.
WE — Executive Vice President — Generation since April 2016. Senior Vice President - Power Generation from January 2014 to March 2016. Vice President - Oak Creek Campus from February 2011 to December 2013.

James A. Schubilske.   Age 51.
WEC Energy Group — Vice President and Treasurer since April 2016. Assistant Treasurer from June 2000 to January 2013.
WE — Vice President and Treasurer since April 2016. Vice President — State Regulatory Affairs from February 2013 to March 2016. Assistant Treasurer from June 2000 to January 2013.

Joan M. Shafer.   Age 63.
WE — Executive Vice President - Human Resources and Organizational Effectiveness since June 2015. Senior Vice President - Customer Services from January 2012 to June 2015. Vice President - Customer Services from January 2004 to January 2012.

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.



2016 Form 10-K3627Wisconsin Electric Power Company
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2013 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 paidcash to our sole common stockholder, Wisconsin Energy.WEC Energy Group. There is no established public trading market for our common stock.

Quarter 2013 2012    
 (Millions of Dollars)
    
(in millions) 2016 2015
First $60.0
 $44.9
 $160.0
 $60.0
Second 110.0
 44.9
 60.0
 60.0
Third 60.0
 44.9
 100.0
 60.0
Fourth 110.0
 44.9
 135.0
 60.0
Total $340.0
 $179.6
 $455.0
 $240.0

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 10, 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.



2016 Form 10-K3728Wisconsin Electric Power Company
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2013 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 2013 2012 2011 2010 2009
Year Ended December 31          
Earnings available for
     common stockholder (Millions)
 $360.0
 $366.1
 $338.4
 $314.2
 $287.4
           
Operating Revenues (Millions)          
Electric $3,308.7
 $3,193.9
 $3,211.3
 $2,936.3
 $2,685.0
Gas 451.9
 385.1
 477.3
 481.6
 564.2
Steam 39.6
 34.3
 39.0
 38.8
 39.1
Total operating revenues $3,800.2
 $3,613.3
 $3,727.6
 $3,456.7
 $3,288.3
           
At December 31 (Millions)          
Total assets $12,285.6
 $12,022.6
 $11,661.3
 $10,170.7
 $8,871.2
Long-term debt and capital lease
     obligations (including current maturities)
 $5,258.8
 $5,276.8
 $5,022.0
 $4,053.5
 $3,092.8
           
As of or for Year Ended December 31          
(in millions) 2016 2015 2014 2013 2012
Operating revenues $3,792.8
 $3,854.1
 $4,059.4
 $3,800.2
 $3,613.3
Net income attributed to common shareholder 364.3
 375.7
 376.7
 360.0
 366.1
Total assets 13,371.5
 13,139.6
 12,597.2
 12,207.2
 12,016.2
Long-term debt and capital lease obligations (excluding current portion) 5,417.6
 5,351.3
 4,875.2
 4,876.7
 4,917.5


CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA
    
  (Millions of Dollars) (a) 
  March June 
Three Months Ended 2013 2012 2013 2012 
Operating revenues $1,004.6
 $946.6
 $880.5
 $840.6
 
Operating income $173.1
 $172.3
 $124.2
 $132.3
 
Earnings available for common
     stockholder
 $104.4
 $115.6
 $72.8
 $83.0
 
          
  September December 
Three Months Ended 2013 2012 2013 2012 
Operating revenues $964.6
 $951.9
 $950.5
 $874.2
 
Operating income $164.6
 $193.3
 $144.0
 $85.4
 
Earnings available for common
     stockholder
 $98.9
 $122.2
 $83.9
 $45.3
 

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


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2013 Form 10-K


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


CORPORATE DEVELOPMENTS

INTRODUCTION
Introduction

Wisconsin Electric Power Company,We are a wholly owned subsidiary of WisconsinWEC Energy is engagedGroup, and derive revenues primarily infrom the businessdistribution and sale of generatingelectricity and distributing electricity in Wisconsin and the Upper Peninsula of Michigan, and distributing natural gas to retail customers 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 GasWG and operate under the trade name of "We Energies." We conduct our business primarily through our utility reportable segment. See Note 21, Segment Information, for more information on our reportable business segments.

CORPORATE STRATEGYEffective January 1, 2017, our customers and electric distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility. See Note 20, Regulatory Environment, and Note 4, Related Parties, for more information.

Business OpportunitiesOn January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information

Corporate Strategy

Our goal is to continue to create long-term value for our customers and WEC Energy Group's shareholders by focusing on the following:

Reliability

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 networks.

Our regulated utility business primarily consists of electric generation assets and the electric and gas distribution assets that serve our electric and gas customers. We operate under a traditional rate regulated cost of service environment. During 2013, our regulated utility earned $605.9 million of operating income. Over the next five years, we expect to invest approximately $2.3 billion to $2.4 billion in this business.Operating Efficiency

We have a 23.0% ownership interest in ATC, a MISO member company regulated by FERC. Our investment in ATC totaled $354.1 million ascontinually look for ways to optimize the operating efficiency of December 31, 2013, and our 2013 pre-tax earningscompany. For example, we received approval from ATC totaled $60.2 million. Over the next five years, in addition to any potential investment through our undistributed earnings in ATC, we expectPSCW to make capital contributions of approximately $114 millionchanges at ERGS to enable the facility to burn coal from the Powder River Basin located in ATC asthe western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.

WEC Energy Group continues to investfocus on integrating and improving business processes and IT infrastructure across all of its companies. We expect these integration efforts to continue to drive operational efficiency.

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 transmission projects.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. See Note 3, Dispositions, for information on the sale of the MCPP.

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.


RESULTS OF OPERATIONS

EARNINGS

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

2012 vs. 2011:   Earnings increased to $366.1 million in 2012 compared with $338.4 million in 2011. Operating income increased $109.7 million between the comparative periods. The increase in operating income was primarily caused by decreased other operation and maintenance expense and decreased fuel and purchased power expenses.


2016 Form 10-K3930Wisconsin Electric Power Company
Table of Contents

One example of how we obtain feedback from our customers is through our "We Care" calls, where our employees contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance in order to improve customer satisfaction.

RESULTS OF OPERATIONS

Consolidated Earnings

Our consolidated earnings for the years ended December 31, 2016, 2015, and 2014 were $364.3 million, $375.7 million, and $376.7 million, respectively. See below for information on the year-over year changes in consolidated earnings.

Non-GAAP Financial Measures

The discussion below addresses the operating income contribution of our utility segment and includes financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies.  Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the years ended December 31, 2016, 2015, and 2014 was $629.5 million, $648.9 million, and $650.4 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.

Utility Segment Contribution to Operating Income
  Year Ended December 31
(in millions) 2016 2015 2014
Electric revenues $3,440.6
 $3,454.4
 $3,445.2
Fuel and purchased power 1,091.8
 1,154.4
 1,228.1
Total electric margins 2,348.8
 2,300.0
 2,217.1
       
Natural gas revenues 352.2
 399.7
 614.2
Cost of natural gas sold 200.3
 244.6
 432.6
Total natural gas margins 151.9
 155.1
 181.6
       
Total electric and natural gas margins 2,500.7
 2,455.1
 2,398.7
       
Other operation and maintenance 1,430.2
 1,384.9
 1,356.4
Depreciation and amortization 325.4
 304.0
 278.3
Property and revenue taxes 115.6
 117.3
 113.6
Operating income $629.5
 $648.9
 $650.4


ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)20132016 Form 10-K

The following table summarizes our consolidated earnings during 2013, 2012 and 2011:

  2013 2012 2011
  (Millions of Dollars)
Utility Gross Margin      
Electric (See below) $2,164.2
 $2,103.6
 $2,052.1
Gas (See below) 173.6
 157.4
 171.1
Steam 26.0
 20.8
 23.7
Total Gross Margin 2,363.8
 2,281.8
 2,246.9
Other Operating Expenses      
Other operation and maintenance 1,417.3
 1,327.8
 1,447.6
Depreciation and amortization 278.6
 257.6
 220.3
Property and revenue taxes 110.0
 113.1
 105.4
Total Operating Expenses 1,805.9
 1,698.5
 1,773.3
Treasury Grant 48.0
 —
 —
Operating Income 605.9
 583.3
 473.6
Equity in Earnings of Transmission Affiliate 60.2
 57.6
 54.9
Other Income and Deductions, net 17.4
 32.3
 62.1
Interest Expense, net 121.4
 113.2
 94.2
Income Before Income Taxes 562.1
 560.0
 496.4
Income Tax Expense 200.9
 192.7
 156.8
Preferred Stock Dividend Requirement 1.2
 1.2
 1.2
Earnings Available for Common Stockholder $360.0
 $366.1
 $338.4



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

Electric Utility Gross Margin

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

maintenance:
  Electric Revenues and Gross Margin MWh Sales
Electric Utility Operations 2013 2012 2011 2013 2012 2011
  (Millions of Dollars) (Thousands)
Customer Class            
Residential $1,208.6
 $1,163.9
 $1,159.2
 8,141.9
 8,317.7
 8,278.5
Small Commercial/Industrial 1,048.0
 1,013.6
 1,006.9
 8,860.4
 8,860.0
 8,795.8
Large Commercial/Industrial 711.9
 744.3
 763.7
 8,673.4
 9,710.7
 9,992.2
Other - Retail 23.4
 22.8
 22.9
 152.3
 154.8
 153.6
Total Retail 2,991.9
 2,944.6
 2,952.7
 25,828.0
 27,043.2
 27,220.1
Wholesale - Other 143.7
 144.4
 154.0
 1,953.5
 1,566.6
 2,024.8
Resale - Utilities 143.2
 53.4
 69.5
 4,382.7
 1,642.4
 2,065.7
Other Operating Revenues 28.4
 51.5
 35.1
 —
 —
 —
Total 3,307.2
 3,193.9
 3,211.3
 32,164.2
 30,252.2
 31,310.6
Electric Customer Choice (a) 1.5
 —
 —
 813.0
 —
 —
Total, including electric customer choice 3,308.7
 3,193.9
 3,211.3
 
 
 
             
             
Fuel and Purchased Power            
Fuel 611.1
 541.6
 644.4
      
Purchased Power 533.4
 548.7
 514.8
      
Total Fuel and Purchased Power 1,144.5
 1,090.3
 1,159.2
      
Total Electric Gross Margin $2,164.2
 $2,103.6
 $2,052.1
      
             
Weather -- Degree Days (b)            
Heating (6,580 Normal)       7,233
 5,704
 6,633
Cooling (730 Normal)       688
 1,041
 793
  Year Ended December 31
(in millions) 2016 2015 2014
Operation and maintenance not included in lines items below $500.2
 $502.9
 $529.2
We Power (1)
 513.2
 510.7
 462.1
Transmission (2)
 273.8
 272.3
 278.6
Regulatory amortizations and other pass through expenses (3)
 96.6
 99.0
 86.4
Earnings sharing mechanism 21.1
 —
 —
Other 25.3
 —
 —
Total other operation and maintenance $1,430.2
 $1,384.9
 $1,356.3

(a)(1)
Represents costs associated with the We Power generation units, including operating and maintenance, as well as lease payments that are billed from We Power to us and then recovered in our rates. During 2016, 2015, and 2014, $528.4 million, $483.4 million, and $475.7 million, respectively, of both lease and operating and maintenance costs were billed to us, with the difference in costs billed and expenses incurred deferred or deducted from the regulatory asset.

(2)
The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2016, 2015, and 2014, $335.3 million, $319.3 million, and $302.4 million, respectively, of costs were billed to us by transmission providers.

(3)
Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

The following tables provide information on delivered volumes by customer class and weather statistics:
  Year Ended December 31
  
MWh (in thousands)
Electric Sales Volumes 2016 2015 2014
Customer class      
Residential 8,136.6
 7,789.3
 7,946.3
Small commercial and industrial * 9,061.1
 8,835.9
 8,843.1
Large commercial and industrial * 9,217.6
 9,492.0
 9,795.3
Other 143.4
 147.7
 148.7
Total retail * 26,558.7
 26,264.9
 26,733.4
Wholesale 1,134.2
 1,234.0
 1,852.8
Resale 8,282.1
 8,577.6
 6,497.9
Total sales in MWh * 35,975.0
 36,076.5
 35,084.1

*Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
(b)
  Year Ended December 31
  
Therms (in millions)
Natural Gas Sales Volumes 2016 2015 2014
Customer class      
Residential 341.7
 341.2
 399.3
Commercial and industrial 186.3
 194.5
 240.4
Total retail 528.0
 535.7
 639.7
Transport 323.8
 306.9
 325.5
Total sales in therms 851.8
 842.6
 965.2
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.


Electric Utility Revenues and Sales

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

Wisconsin net retail pricing increases of $115.6 million ($177.7 million less $62.1 million related to Section 1603 Renewable Energy Treasury Grant (Treasury Grant) bill credits), which is primarily related to our 2013 Wisconsin Rate Case. For information on the Treasury Grant and the rate order in the 2013 rate case, see -- Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments and -- Rates and Regulatory Matters, respectively.
A $89.8 million increase in sales for resale due to increased sales into the MISO Energy Markets as a result of increased availability of our generating units.
A $48.0 million decrease in large commercial/industrial sales due to the two iron ore mines that switched to an alternative electric supplier effective September 1, 2013. See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Restructuring in Michigan, for a discussion of the impact of industry restructuring in Michigan on our electric sales.
A $23.1 million decrease in other operating revenues, primarily driven by the amortization of $25.9 million in 2012 related to the settlement with the United States Department of Energy (DOE). For additional information on the DOE settlement, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- 2012 Fuel Cost Plan Request.

2016 Form 10-K4132Wisconsin Electric Power Company
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  Year Ended December 31
  Degree Days
Weather * 2016 2015 2014
Heating (6,679 normal) 6,068
 6,468
 7,616
Cooling (694 normal) 991
 622
 464

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

2016 Compared with 2015

Electric Utility Margins

Electric utility margins increased $48.8 million during 2016, compared with 2015. The significant factors impacting the higher electric utility margins were:

A $38.9 million increase related to higher retail sales volumes during 2016, primarily driven by warmer summer weather. As measured by cooling degree days, 2016 was 59.3% warmer than 2015.

The expiration of $12.5 million of bill credits refunded to customers in 2015 related to the Treasury Grant we received in connection with our biomass facility.

Natural Gas Utility Margins

Natural gas utility margins decreased $3.2 million during 2016, compared with 2015. The most significant factor impacting the lower natural gas utility margins was a decrease in sales volumes during 2016, primarily driven by warmer winter weather. As measured by heating degree days, 2016 was 6.2% warmer than 2015.

Operating Income

Operating income at the utility segment decreased $19.4 million during 2016, compared with 2015. The decrease was driven by the $65.0 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes), partially offset by the $45.6 million net increase in margins discussed above.

The significant factors impacting the increase in operating expenses in 2016, compared with 2015, were:

A $25.3 million increase in expenses in 2016 related to a focus on projects that were beneficial to customers and the communities within our service territories.

A $21.4 million increase in depreciation and amortization, driven by an overall increase in utility plant in service. In November 2015, we completed the conversion of the fuel source for VAPP from coal to natural gas.

A $21.1 million expense related to our earnings sharing mechanism in place, effective January 1, 2016. See the PSCW conditions of approval related to our parent's acquisition of Integrys in Note 2, Acquisitions, for more information.

An $11.1 million increase in expenses related to various regulatory matters.

These increases in operating expenses were partially offset by a $16.4 million positive impact from the sale of the MCPP in April 2016, including a gain on sale and lower operating costs in 2016. See Note 3, Dispositions, for more information.


ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)20132016 Form 10-K33Wisconsin Electric Power Company

A return to more normal summer weather as compared to the prior year that decreased electric revenues by an estimated $17.7 million.
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As measured2015 Compared with 2014

Electric Utility Margins

Electric utility margins increased $82.9 million during 2015, compared with 2014. The significant factors impacting the higher electric utility margins were:

A $38.4 million increase as a result of the PSCW rate order, effective January 1, 2015. See Note 20, Regulatory Environment, for more information.

A $35.0 million increase driven by cooling degree days, 2013 wasthe escrow accounting treatment of the SSR revenues in the PSCW rate order, effective January 1, 2015. 5.8%See Note 20, Regulatory Environment, for more information cooler than normal, and .33.9% cooler than 2012. Residential sales decreased by 2.1%, primarily

A $24.2 million increase due to the weather. Sales to our large commercial/industrial customers decreased by 10.7% primarily becausereturn of a decrease in sales to the two iron ore mines as customers in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased 3.0%.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 addition, other smaller2015, 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 have switchedin a future rate proceeding. Michigan state law allows the mines to switch to an alternative electric supplier. Wholesale - Other sales increased 24.7% primarily due to increased off-peak energy sales which generate lower incremental revenue because the majority of our wholesale revenue is tied to demand.supplier after sufficient notice.

2012 vs. 2011:   Our electric utility operating revenues decreased by $17.4A $10.4 million or 0.5%, when compared to 2011. The most significant factors that caused a change in revenues were:

Favorable weather as compared to 2011 that increased electric revenues by an estimated $28.5 million.
Other operating revenues increased by approximately $16.4 million, driven by the $25.9 million amortizationpositive impact from collections of the settlement with the DOE.
A planned outage at an iron ore mine in 2012 and the conversion to self-generation of two other large customers decreased electric revenues by an estimated $20.4 million.
A $16.2 million reduction in sales for resale due to reduced sales into the MISO Energy Markets.
Lower MWh sales to our wholesale customers, which decreased revenue by an estimated $12.4 million as compared to 2011.

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

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


Electric Fuel and Purchased Power Expenses

2013 vs. 2012:   Our electric fuel and purchased power costs increasedas compared with costs approved in rates in 2015, as compared with 2014. Under the Wisconsin fuel rules, our margins are impacted by $54.2 million,under or approximately 5.0%, when compared to 2012. This increase was primarily caused by a 6.3% increase in total MWh sales, partially offset by a decrease in our average costover-collections of fuel because of outage timing and a decrease in coal costs.

2012 vs. 2011:   Our electriccertain fuel and purchased power costs decreased by $68.9that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

A $6.2 million or approximately 5.9%, when comparedincrease primarily due to 2011.lower fly ash removal costs in 2015.

A partially offsetting $22.3 million decrease related to sales volume variances in 2015. This decrease was driven by lower margins from residential customers in 2015, primarily causeddue 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 3.4%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.

Natural Gas Utility Margins

Natural gas utility margins decreased $26.5 million during 2015, compared with 2014. The significant factors impacting the lower natural gas utility margins were:

A $14.9 million decrease in total MWh sales volumes in 2015, 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.

A $10.7 million decrease in margins as a reductionresult of the impact of the PSCW rate order, effective January 1, 2015. See Note 20, Regulatory Environment, for more information.

Operating Income

Operating income at the utility segment decreased $1.5 million during 2015, compared to 2014. The decrease was driven by $57.9 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes), substantially offset by the $56.4 million net increase in margins discussed above.

The significant factors impacting the increase in operating expenses were:

A $48.6 million increase from higher lease expense related to the We Power leases and associated operating and maintenance expenses as approved in our average cost of fuel and purchased power because of lower natural gas prices.PSCW rate order, effective January 1, 2015.


2016 Form 10-K4234Wisconsin Electric Power Company
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A $25.7 million increase in depreciation and amortization expense, driven by:

◦An overall increase in utility plant in service in 2015. In November 2015, we completed the conversion of the fuel source for VAPP from coal to natural gas.

◦A new depreciation study approved by the PSCW, effective January 1, 2015.

◦A $7.7 million reduction in income received in 2015 from the Treasury Grant we received in connection with the completion of our biomass plant in November 2013. The lower grant income corresponds to lower bill credits provided to our retail electric customers in Wisconsin.

A $12.6 million increase in regulatory amortizations and other pass through expenses.

These increases in operating expenses were partially offset by:

A $7.4 million decrease in electric distribution costs and amortization of design software, partially offset by higher electric maintenance costs.

A $6.9 million decrease in employee benefit costs in 2015 driven by lower performance units share-based compensation, deferred compensation, and medical costs.

Equity in Earnings of Transmission Affiliate
  Year Ended December 31
(in millions) 2016 2015 2014
Equity in earnings of transmission affiliate $55.5
 $47.8
 $57.9

2016 Compared with 2015

Earnings from our ownership interest in ATC increased $7.7 million when compared to 2015, primarily driven by 2015 earnings from our investment in ATC being negatively impacted by an ALJ initial decision in December 2015, that was later affirmed by a FERC order in 2016. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information on these decisions.

See Note 5, Investment in American Transmission Company, for information about the transfer of our ATC ownership interests.

2015 Compared with 2014

Earnings from our ownership interest in ATC decreased $10.1 million when compared to 2014, driven by 2015 earnings from our investment in ATC being negatively impacted by an ALJ initial decision in December 2015.

Consolidated Other Income, Net
  Year Ended December 31
(in millions) 2016 2015 2014
AFUDC – Equity $4.2
 $5.7
 $4.4
Gain on asset sales —
 —
 4.3
Other, net 4.9
 5.5
 —
Other income, net $9.1
 $11.2
 $8.7

Consolidated Interest Expense
  Year Ended December 31
(in millions) 2016
2015
2014
Interest expense $117.6
 $119.0
 $116.5


ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)20132016 Form 10-K35Wisconsin Electric Power Company
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Gas Utility Revenues, Gross Margin and Therm DeliveriesIncome Tax Expense
  Year Ended December 31
  2016
2015
2014
Effective tax rate 36.6% 36.0% 37.1%

The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2013, 2012 and 2011.

Gas Utility Operations 2013 2012 2011
  (Millions of Dollars)
       
Operating Revenues $451.9
 $385.1
 $477.3
Cost of Gas Sold 278.3
 227.7
 306.2
Gross Margin $173.6
 $157.4
 $171.1

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 2013, 2012 and 2011:

  Gross Margin Therm Deliveries
Gas Utility Operations 2013 2012 2011 2013 2012 2011
  (Millions of Dollars) (Millions)
Customer Class            
Residential $117.8
 $106.1
 $114.7
 380.8
 294.3
 339.4
Commercial/Industrial 37.5
 33.0
 38.1
 210.9
 165.3
 198.7
Interruptible 0.5
 0.5
 0.5
 5.4
 5.0
 5.3
Total Retail 155.8
 139.6
 153.3
 597.1
 464.6
 543.4
Transported Gas 16.5
 16.5
 16.3
 327.6
 344.5
 294.4
Other 1.3
 1.3
 1.5
 —
 —
 —
Total $173.6
 $157.4
 $171.1
 924.7
 809.1
 837.8
             
Weather -- Degree Days (a)            
Heating (6,580 Normal)       7,233
 5,704
 6,633

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

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

2012 vs. 2011:   Our total retail gas margin decreased by $13.7 million, or approximately 8.9%, when compared to 2011 primarily because of a decrease in sales volumes as a result of warmer winter weather. As measured by heating degree days, 2012 was 14.0% warmer than 2011 and 14.4% warmer than normal.

Transported gas volumes increased by 17.0% when compared to 2011. Virtually all of the volume increase related to gas used in electric generation, which has a small impact on margin.


Other Operation and Maintenance Expense

2013 vs. 2012:   Our other operation and maintenance expense increased by $89.5 million, or approximately 6.7%, when compared to 2012. This increase is primarily driven by the reinstatement of $148.0 million of regulatory amortizations, offset in part by continued cost control efforts. For additional information on the regulatory amortizations, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- 2012 Wisconsin Rate Case.2016 Compared with 2015

Our operationeffective tax rate was 36.6% in 2016 compared with 36.0% in 2015. This increase in our effective tax rate was primarily related to Treasury Grant activity in 2015. See Note 14, Income Taxes, for more information. We expect our 2017 annual effective tax rate to be between 36.0% and maintenance expenses are influenced37.0%.

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.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows for the years ended December 31:
(in millions) 2016 2015 2014 Change in 2016 Over 2015 Change in 2015 Over 2014
Cash provided by (used in):          
Operating activities $848.4
 $674.4
 $862.8
 $174.0
 $(188.4)
Investing activities (436.8) (520.2) (567.5) 83.4
 47.3
Financing activities (423.3) (151.1) (296.4) (272.2) 145.3

Operating Activities

2016 Compared with 2015

Net cash provided by among other things, labor costs, employee benefit costs, plant outagesoperating activities increased $174.0 million during 2016, driven by:

A $158.7 million net increase in cash related to $100.2 million of cash received for income taxes during 2016, compared with $58.5 million of cash paid for income taxes during 2015. The increase in cash received was due to a federal income tax refund received in 2016, primarily the result of the extension of bonus depreciation in December 2015.

A $144.2 million increase in cash resulting from lower payments for natural gas and amortizationfuel and purchased power, due to lower commodity prices and warmer weather during the 2016 heating season. The average per-unit cost of regulatory assets.natural gas sold decreased 17.4% in 2016.

A $99.6 million decrease in contributions and payments to our pension and OPEB plans during 2016.

A $29.1 million increase in cash due to lower collateral requirements during 2016, driven by an increase in the fair value of our derivative instruments. See Note 18, Derivative Instruments, for more information.

These increases in net cash provided by operating activities were partially offset by:

Cash payments of $116.0 million for transfers of certain benefit-related liabilities to WBS during 2016.

A $91.6 million decrease in cash related to lower overall collections from customers. Collections from customers decreased primarily because of lower commodity prices and warmer weather during the 2016 heating season.


2016 Form 10-K4336Wisconsin Electric Power Company
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A $55.8 million decrease in cash driven by higher payments for operating and maintenance costs during 2016.

2015 Compared with 2014

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

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

A $76.2 million decrease in cash in 2015 related to the Treasury Grant we received in 2014 in connection 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, during 2015.

Investing Activities

2016 Compared with 2015

Net cash used in investing activities decreased $83.4 million during 2016, driven by:

A $49.7 million decrease in cash paid for capital expenditures, which is discussed in more detail below.

Proceeds of $31.7 million received from the sale of MCPP in April 2016. See Note 3, Dispositions, for more information.

Cash received of $13.1 million during 2016 related to transfers of certain software to WBS.

These decreases in net cash used in investing activities were partially offset by an $11.5 million increase in capital contributions to ATC, driven by the continued investment in equipment and facilities by ATC to improve reliability.

2015 Compared with 2014

Net cash used in investing activities decreased $47.3 million during 2015, driven by a decrease in cash paid for capital expenditures during 2015, which is discussed in more detail below.

Capital Expenditures

Capital expenditures for the years ended December 31 were as follows:
  2016 2015 2014 Change in 2016 Over 2015 Change in 2015 Over 2014
Capital expenditures $469.5
 $519.2
 $561.8
 $(49.7) $(42.6)

2016 Compared with 2015

The decrease in cash paid for capital expenditures during 2016 was partially related to the completion in November 2015 of the coal to natural gas conversion project at VAPP. Also contributing to the decrease were lower payments during 2016 for environmental compliance projects and electric distribution upgrades.

2015 Compared with 2014

The decrease in cash paid for capital expenditures during 2015 was primarily 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.

See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements – Capital Expenditures and Significant Capital Projects for more information.


ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)20132016 Form 10-K


2012 vs. 2011:   Our other operation and maintenance expense decreased by $119.8 million, or approximately 8.3%, when compared to 2011. This decrease is primarily due to the one year suspension of $148.0 million of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case.


Depreciation and Amortization Expense

2013 vs. 2012:   Depreciation and Amortization expense increased by $21.0 million, or approximately 8.2%, when compared to 2012. This increase was primarily because of an overall increase in utility plant in service. The emission control equipment for units 5 and 6 of the Oak Creek Air Quality Control System (AQCS) project went into service in March 2012, and for units 7 and 8 in September 2012. In addition, our new biomass plant went into service in November 2013. For additional information on the AQCS and biomass facility, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Oak Creek Air Quality Control System and -- Renewables, Efficiency, and Conservation, respectively.

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

2012 vs. 2011:   Depreciation and Amortization expense increased by $37.3 million, or approximately 16.9%, when compared to 2011. This increase was primarily because of an overall increase in utility plant in service. The Glacier Hills Wind Park went into service in December 2011. In addition, the emission control equipment for units 5 and 6 of the Oak Creek AQCS project went into service in March 2012, and for units 7 and 8 in September 2012.


Treasury Grant

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

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


Other Income and Deductions, net

Other Income and Deductions, net 2013 2012 2011
  (Millions of Dollars)
       
AFUDC - Equity $17.6
 $34.9
 $59.2
Other, net (0.2) (2.6) 2.9
Total Other Income and Deductions, net $17.4
 $32.3
 $62.1

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

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

2012 vs. 2011:   Other income and deductions, net decreased by approximately $29.8 million, or 48.0%, when compared to 2011. This decrease primarily relates to lower AFUDC - Equity related to the Glacier Hills Wind Park, which went into service in December 2011, as well as the Oak Creek AQCS project which emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8.

4437Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K


Interest Expense, net

Interest Expense, net 2013 2012 2011
  (Millions of Dollars)
       
Gross Interest Costs $128.8
 $127.7
 $118.9
Less: Capitalized Interest 7.4
 14.5
 24.7
Interest Expense, net $121.4
 $113.2
 $94.2

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

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

2012 vs. 2011:   Our 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.


Income Tax Expense

2013 vs. 2012:   Our effective tax rate was 35.7% in 2013 compared with 34.4% in 2012. This increase in our effective tax rate was primarily the result of reduced domestic production activities deductions and AFUDC - Equity. For further information, see Note G -- Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2014 annual effective tax rate to be between 37.5% and 38.5%.

2012 vs. 2011:   Our effective tax rate was 34.4% in 2012 compared with 31.6% in 2011. This increase in our effective tax rate was primarily the result of decreased AFUDC - Equity.


LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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

  2013 2012 2011
  (Millions of Dollars)
Cash Provided by (Used in)      
Operating Activities $862.6
 $807.0
 $543.9
Investing Activities $(560.1) $(605.6) $(762.1)
Financing Activities $(311.5) $(180.0) $207.6

Operating Activities

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

45Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K

amortization expense. Included in the higher amortization expense is a $120.9 million increase in the amortization of regulatory items. Partially offsetting these items is an increase in accounts receivable and accrued revenues of $201.3 million because of colder winter weather and the Treasury Grant.

2012 vs. 2011:   Cash provided by operating activities was $807.0 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.

Investing Activities

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

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.

Financing Activities

The following table summarizes our cash flows from financing activities:2016 Compared with 2015

  2013 2012 2011
  (Millions of Dollars)
       
Dividends to Wisconsin Energy $(340.0) $(179.6) $(239.6)
Net Increase in Debt 18.4
 0.1
 440.7
Other 10.1
 (0.5) 6.5
Cash (Used in) Provided by Financing $(311.5) $(180.0) $207.6

2013 vs. 2012:   CashNet cash used in financing activities was $311.5increased $272.2 million during 2013 compared2016, driven by:

A $250.0 million net decrease in cash due to $180.0 million during 2012. During 2013, we retired $300.0the issuance of $500.0 million of long-term debt and issued $250during 2015, partially offset by the repayment of $250.0 million of long-term debt. The net proceedsdebt during 2015. A portion of the debtthis issuance werewas also used to repay short-term debt and for other corporate purposes. In addition,during 2015. We did not issue or repay any long-term debt in 2016.

A $215.0 million increase in dividends paid on common stock during 2016. During 2016, we paid $160.4 million morespecial dividends to Wisconsin Energy during 2013 as compared to 2012 which includes $100 million of special dividendsour parent to balance our capital structure.

2012 vs. 2011:   CashThese increases in net cash used in financing activities was $180.0were partially offset by a $177.8 million net increase in cash due to $15.0 million of net borrowings of commercial paper during 2016, compared with $162.8 million of net repayments of commercial paper during 2015.

2015 Compared with 2014

Net cash used in financing activities decreased $145.3 million during 2012 compared to $207.62015, driven by:

A $300.0 million provided by financing activities during 2011. This change is primarilyincrease in cash due to changesa $250.0 million increase in our debt levels. During 2012, we issued $250 millionthe issuance of long-term debt during 2015 and $50.0 million of lower repayments of long-term debt during 2015. A portion of this issuance was used the net proceeds to repay short-term debt and for other general corporate purposes comparedduring 2015.

A $150.0 million decrease in dividends paid on common stock during 2015. In 2014, we paid special dividends to $300our parent to balance our capital structure.

These decreases in net cash used in financing activities were partially offset by a $294.7 million net decrease in cash related to $162.8 million of long-term debt issued in 2011. In addition, short-term debt decreased $249.9net repayments of commercial paper during 2015, compared with $131.9 million in 2012 compared to a $140.7 million increase in 2011.of net borrowings of commercial paper during 2014.

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.


46Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K

CAPITAL RESOURCES AND REQUIREMENTSSignificant Financing Activities

WorkingFor more information on our financing activities, see Note 12, Short-Term Debt and Lines of Credit, and Note 13, Long-Term Debt and Capital Lease Obligations.

As of December 31, 2013, our current liabilities exceeded our current assets by approximately $44.3 million. Included in our current liabilities is approximately $379.5 million of long-term debt
Capital Resources 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.Requirements

Capital Resources

Liquidity

We anticipate meeting our capital requirements during 2014 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, 2013, we had approximately $493.9 million of available, undrawn lines under our bank back-up credit facility. As of December 31, 2013, we had approximately $174.5 million of commercial paper outstanding that was supported by the available line of credit. During 2013, our maximum commercial paper outstanding was $354.5 million with a weighted-average interest rate of 0.22%. For additional information regarding our commercial paper balances during 2013, see Note K -- Short-Term Debt in the Notes to Consolidated Financial Statements.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facility asSee Note 12, Short-Term Debt and Lines of December 31, 2013:Credit, for more information on our credit facility.

Total Facility Letters of Credit Credit Available 
Facility
Expiration
(Millions of Dollars)  
       
$500.0 $6.1
 $493.9
 December 2017

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

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

Capitalization Structure 2013 2012
  (Millions of Dollars)
         
Common Equity $3,406.8
 38.3% $3,366.4
 38.2%
Preferred Stock 30.4
 0.3% 30.4
 0.3%
Long-Term Debt (a) 2,467.3
 27.8% 2,516.7
 28.6%
Capital Lease Obligations (a) 2,791.5
 31.4% 2,760.1
 31.4%
Short-Term Debt (b) 197.3
 2.2% 128.9
 1.5%
Total $8,893.3
 100.0%
$8,802.5
 100.0%
         
(a) Includes current maturities        
(b) Includes subsidiary note payable to Wisconsin Energy    

2016 Form 10-K4738Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K


For a summaryTable 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.Contents

At December 31, 2016, we were in compliance with all covenants related to outstanding short-term and long-term debt. We areexpect to be in compliance with all such debt covenants for the obligor under two seriesforeseeable future. See Note 13, Long-Term Debt and Capital Lease Obligations, for more information on our long-term debt.

Working Capital

Although not the case as of tax exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009,December 31, 2016, our current liabilities sometimes exceed our current assets. If this were to occur, we terminated letterswould not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit that provided creditin place for ongoing operations. We also can access the capital markets to finance our construction programs and liquidity support for the bonds, which resulted in a mandatory tenderto refinance current maturities of the bonds. We issued commercial paper to fund the purchase of the bonds. As of December 31, 2013, the repurchased bonds were still outstanding, but were not reported as long-term debt, because they are held by 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.if necessary.

Bonus Depreciation Provisions

The American Taxpayer Relief Act of 2012 was signed into law on January 2, 2013, which extended the 50% bonus depreciation rules to include assets placed in service in 2013. These rules apply to the biomass plant we constructed in Rothschild, which went into service in November 2013. As a result of the increased federal tax depreciation for 2013 and prior years, we did not make federal income tax payments for 2013 and do not anticipate making federal income tax payments for 2014.
Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We doHowever, we 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'sS&P Global Ratings Services (S&P) and/or Baa3 at Moody's Investor Service (Moody's). As of December 31, 2013, we estimate that the collateral or the termination payments required under these agreements totaled approximately $211.8 million. Generally, collateral may be provided by a Wisconsin Energy guaranty, letter of credit or cash.Investors Service. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

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

In January 2014, Moody's raised our rating (senior unsecured to A1 from A2), and assigned us a stable ratings outlook. Our commercial paper rating remained at P-1.

In June 2013, S&P affirmed our ratings (commercial paper, A-2; senior unsecured, A-) and revised our ratings outlook from positive to stable.

In June 2013, Fitch Ratings affirmed our ratings (commercial paper, F1; senior unsecured, A+) and our stable ratings outlook.

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

Capital Requirements

Capital Expenditures:   Our estimated capital expenditures for the next three years are as follows:
 (Millions of Dollars)
2014$530.1
2015498.1
2016449.3
Total$1,477.5

48Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K


The majority of spending consists of upgrading our electric and gas distribution systems. Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such as air quality standards, renewable energy standards and electric reliability initiatives that impact 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 $1.4 billion as of December 31, 2013. These trusts hold investments that are subject to the volatility of the stock market and interest rates.

During 2013, we made no contributions to our qualified pension plans or our qualified Other Post-Retirement Employee Benefit (OPEB) plans. During 2012, we contributed $88.5 million to our qualified pension plans and $4.4 million to our qualified OPEB plans. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note N -- Benefits in the Notes to Consolidated Financial Statements.

Off-Balance Sheet Arrangements:   We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support 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, 2013:

2016:
  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) $4,419.0
 $410.8
 $504.8
 $419.5
 $3,083.9
Capital Lease Obligations (c) 10,070.3
 416.0
 883.9
 839.2
 7,931.2
Operating Lease Obligations (d) 40.5
 3.9
 7.6
 6.3
 22.7
Purchase Obligations (e) 11,755.2
 807.9
 1,164.1
 958.9
 8,824.3
Other Long-Term Liabilities 871.9
 91.9
 174.4
 175.3
 430.3
Total Contractual Obligations $27,156.9
 $1,730.5
 $2,734.8
 $2,399.2
 $20,292.4
  
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)
 $4,988.1
 $114.9
 $723.5
 $500.1
 $3,649.6
Capital lease obligations (3)
 9,024.7
 432.0
 866.4
 869.8
 6,856.5
Operating lease obligations (4)
 33.5
 4.4
 4.7
 2.7
 21.7
Energy and transportation purchase obligations (5)
 10,216.1
 685.7
 1,118.2
 1,038.4
 7,373.8
Purchase orders (6)
 266.9
 60.1
 86.6
 52.1
 68.1
Pension and OPEB funding obligations (7)
 12.5
 4.9
 7.6
 —
 —
Total contractual obligations $24,541.8
 $1,302.0
 $2,807.0
 $2,463.1
 $17,969.7

(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.leases with We Power.

(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 servicesservices.

(7)
Obligations for utility operations. This includes the power purchase agreement for Point Beach.pension and OPEB plans cannot reasonably be estimated beyond 2019.

2016 Form 10-K39Wisconsin Electric Power Company
Table of Contents


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 --14, Income TaxesTaxes.

AROs in the Notes to Consolidated Financial Statementsamount of $61.5 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 obligationsObligations 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)  
2017 $656.6
2018 595.3
2019 574.3
Total $1,826.2
49Wisconsin Electric Power Company

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

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

For information related to our common stock matters, see Note 10, Common Equity.

Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $1.3 billion as of December 31, 2016. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $8.0 million, $107.6 million, and $10.4 million to our pension and OPEB plans in 2016, 2015, and 2014, 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 15, 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 that 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 12, Short-Term Debt and Lines of Credit, and Note 19, Variable Interest Entities.

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:


2016 Form 10-K40Wisconsin Electric Power Company
Table of Contents

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.commissions. Our primary regulator is the PSCW. See Note 20, 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 thesethose costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recoveryregulators. Recovery of these deferred costs in future rates is subject to the review and approval ofby those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these deferred costs is not approved by our regulators, the costs arewould be charged to income in the current period. In general, our regulatory assets are recovered inover a period of 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, 2013,2016, our regulatory assets totaled $1,370.3were $2,036.6 million, and our regulatory liabilities totaled $634.2 million.were $864.1 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. The fuel rules allow for a deferral ofthe changes 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 – D. Regulation for more information regarding the fuel rules, see Rates and Regulatory Matters -- Wisconsin Fuel Proceedings.on these mechanisms.

Natural Gas Costs:   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.

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.
Weather

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

Weather:Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages.normal temperatures. Our electric revenues and salesutility margins 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 salesutility margins are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2013, 20122016, 2015 and 2011,2014, as measured by degree days, may be found above in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

Interest Rates

We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest 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 at December 31, 2016, and December 31, 2015, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $1.6 million and $1.4 million in 2016 and 2015, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.


2016 Form 10-K5041Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K

Interest Rate:We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding asTable of December 31, 2013. Borrowing levels under these arrangements vary from period to period depending on capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels.Contents

We performed an interest rate sensitivity analysis as of December 31, 2013 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2013, we had $174.5 million of commercial paper outstanding with a weighted-average interest rate of 0.22% and $147.0 million of variable rate long-term debt outstanding with a weighted-average interest rate of 0.50%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $3.2 million.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 PSCW.

The fair value of our trust fund assets as of December 31, 2013 wasand expected long-term returns were approximately:

  Millions of Dollars
   
Pension trust funds $1,168.9
Other post-retirement benefits trust funds $222.4

The expected long-term rate of return on plan assets for 2014 is 7.25% and 7.5%, respectively, for the pension and OPEB plans.
(in millions) As of December 31, 2016 Expected Return on Assets in 2017
Pension trust funds $1,102.8
 7.00%
OPEB trust funds $205.1
 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.

Economic Conditions:   Conditions

Our service territory isterritories are primarily within the state of Wisconsin and the Upper Peninsula of Michigan. WeWisconsin. As such, we are exposed to market risks in the regional midwestMidwest 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 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. Risk Factors.


POWER THE FUTURE

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

51Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K


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

We 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. The warranty claim for costs incurred to repair steam turbine corrosion damage identified on both units was scheduled to go to arbitration in October 2013, but we entered into a settlement agreement with Bechtel in June 2013 resolving the claim, as well as several other warranty claims. This settlement did not have a material impact to our financial statements. We, along with Bechtel, continue to work through two remaining items.

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


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. For the year ended December 31, 2013, we estimate that approximately 87% of our electric revenues were regulated by the PSCW, 4% were regulated by the MPSC and the balance of our electric revenues was regulated by FERC. Because of the loss of several Michigan customers to an alternative electric supplier, the percentage of revenues regulated by the MPSC is likely to decline in the future. In Wisconsin, a general rate case is typically filed every two years. All of our natural gas and steam revenues are regulated by the PSCW. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.

General Rate Proceedings

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

A net bill increase related to non-fuel costs for our Wisconsin retail electric customers of approximately $70 million (2.6%) for 2013. This amount reflects an offset of approximately $63 million (2.3%) of bill credits related to the proceeds of the Treasury Grant, including related tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133 million (4.8%) for 2013.
An electric rate increase for Wisconsin Electric's Wisconsin electric customers of approximately $28 million (1.0%) for 2014, and a $45 million (1.6%) reduction in bill credits.
Recovery of a forecasted increase in fuel costs of approximately $44 million (1.6%) for 2013.
A rate decrease of approximately $8 million (1.9%) for our natural gas customers for 2013, with no rate adjustment in 2014. The new rates reflect a $6.4 million reduction in bad debt expense.
An increase of approximately $1.3 million (6.0%) for our Downtown Milwaukee (Valley) steam utility customers for 2013 and another $1.3 million (6.0%) in 2014.
An increase of approximately $1 million (7.0%) in 2013 and $1 million (6.0%) in 2014, respectively, for our Milwaukee County steam utility customers.


52Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K

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

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

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

2012 Michigan Rate Case:In July 2011, we filed a $17.5 million rate increase request with the MPSC, primarily to recover the costs of environmental upgrades and OC 2. Pursuant to Michigan law, we self-implemented a $5.7 million interim electric base rate increase in January 2012. This increase was partially offset by a refund of $2.7million 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. In 2014, we expect to seek a base rate increase to be effective in 2015.

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;
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. The PSCW issued a final decision, increasing annual Wisconsin retail rates by $25.4 million effective April 29, 2011. The net increase was driven primarily by an increase in the delivered cost of coal.

2010 Michigan Rate Increase Request:   In July 2009, we filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. In July 2010, the MPSC issued its final order, approving a total increase of $23.5 million annually, or 14.2%. In August 2010, our largest customers, two iron ore mines, filed an appeal with the MPSC regarding this rate order. In October 2010, the MPSC ruled on the mines' appeal and reduced the rate increase by approximately $0.3 million annually, effective November 1, 2010. In November 2010, the mines filed a Claim of Appeal of the October 2010 order with the Michigan Court of Appeals. In December 2010, the MPSC filed a Motion for Remand with the Court of Appeals. In March 2011, the Court of Appeals denied the Motion for Remand. All briefs have been filed and the case is awaiting scheduling of oral argument.

Wisconsin Fuel Proceedings

Embedded within our base electric rates is an amount to recover fuel costs. The Wisconsin retail fuel rules require the company to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs

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that are outside of the utility's symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the utility's approved fuel cost plan. The deferred fuel costs are subject to an excess revenues test.

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

2012 Fuel Cost Plan Request:In August 2011, we filed a $50 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The primary reasons for the increase were projected higher coal, coal transportation and purchased power costs. In January 2012, the PSCW issued an order which provided for an increase in fuel costs of approximately $26 million, offset by approximately $26 million from the settlement with the DOE.

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

Other Rate Matters

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

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 Wisconsin. In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed us to use escrow accounting whereby we deferred transmission costs that exceeded amounts embedded in our rates. We were allowed to earn a return on the unrecovered transmission costs we deferred at our weighted-average cost of capital. As of December 31, 2013, we had $126.8 million of unrecovered transmission costs related to prior deferrals that are not subject to escrow accounting because our 2008 and 2010 PSCW rate orders provided for recovery of these costs. In the 2013 Wisconsin Rate Case, the PSCW reauthorized escrow accounting for future transmission costs and we are allowed to accrue these costs on a net of tax basis at the short-term debt rate.

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

Renewables, Efficiency and Conservation:   In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. A utility's renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Our baseline renewable energy percentage is 2.27%. Under Act 141, we 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, 2013, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. To comply with increasing requirements, we have constructed and contracted for several hundred megawatts of wind generation and constructed a 50 MW biomass facility at Domtar Corporation's

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Rothschild, Wisconsin paper mill site that went into commercial operation on November 8, 2013. Wood waste and wood shavings are used to produce renewable electricity and will also support Domtar's sustainable papermaking operations. The final cost of completing this project was $269.0 million, excluding AFUDC. We also own four wind sites, consisting of 200 turbines with an installed capacity of 338 MW and a dependable capability of 66 MW.

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

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

Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the Wisconsin Department of Administration back to the PSCW and/or contracted third parties. In addition, Act 141 required that 1.2% of utilities' annual operating revenues be used to fund these programs in 2013. The funding required by Act 141 for 2014 is also 1.2% of annual operating revenues.

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


ELECTRIC SYSTEM RELIABILITY

We continue to upgrade our electric distribution system, including substations, transformers and lines. We had adequate capacity to meet the MISO calculated planning reserve margin during 2013 and 2012. All of our generating plants performed as expected during the warmest periods of the summer and all power purchase commitments under firm contract were received. During this period, public appeals for conservation were not required and we did not interrupt or curtail service to non-firm customers who participate in load management programs. We expect to have adequate capacity to meet the planning reserve margin requirements during 2014. However, extremely hot weather, unexpected equipment failure or unavailability across the 15-state MISO market footprint could require us to call upon load management procedures.


ENVIRONMENTAL MATTERS

Overview

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


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Air Quality

EPA - Consent Decree:   In April 2003, we reached a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired generating facilities. In July 2003, the Consent Decree was amended to include the state of Michigan, and in October 2007, the U.S. District Court for the Eastern District of Wisconsin approved and entered the amended Consent Decree. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS that began service in 2012. In order to achieve the reductions agreed to in the Consent Decree, over the past 10 years we have installed new pollution control equipment, including the Oak Creek AQCS, upgraded existing equipment and retired certain older coal units at a cost of approximately $1.2 billion. We do not expect future costs to have a material impact on our consolidated financial statements.

National Ambient Air Quality Standards (NAAQS)

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

In January 2010, the EPA announced its decision to further lower the 2008 8-hour ozone standard. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard. In January 2014, environmental groups petitioned the U.S. District Court for the Northern District of California to order the EPA to propose a new ozone standard by the end of 2014 and to finalize the standard by October 2015. We expect that the EPA could lower the current 8-hour ozone standard from its current level.

Fine Particulate Standard:   In 2009, the EPA designated three counties in southeast Wisconsin (Milwaukee, Waukesha and Racine) as not meeting the daily standard for 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 SIP including reasonably available control technology (RACT) regulations. In December 2012, the EPA re-proposed this determination along with further clarification of its authority to suspend RACT and other SIP requirements. Until the EPA finalizes this action and redesignates the three counties to attainment, our generating facilities in the non-attainment counties will continue to be subject to more stringent construction permitting requirements and emission offset provisions. Also in December 2012, the EPA issued a revised and more stringent annual 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. This standard represented a significant change from the previous SO2 standard. The implementation guidance for the new standard, among other things, required attainment designations to be based on modeling rather than monitoring. Traditionally, attainment designations were based on monitored data. The EPA has since advised that it is revisiting this implementation guidance. The EPA issued two technical assistance documents for comment in 2013 and expects to issue a rule in 2014 that will establish requirements for characterizing SO2 air quality in priority areas.

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

If the new standard remains in place, we do not believe that we will need to make any significant additional expenditures at the majority of our generating units because of prior investments in pollution control equipment.

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However, if the new standard does remain in place we believe that additional environmental controls will be required at PIPP located in the Upper Peninsula of Michigan.
In November of 2012 we entered into a joint venture agreement with Wolverine whereby Wolverine would pay for the installation of the air quality control systems at PIPP and receive a minority undivided ownership interest in the plant in return. However, in light of the loss of retail electric customers in Michigan due to that state’s alternative electric supplier program (see Restructuring in Michigan under Industry Restructuring and Competition), we re-evaluated options related to the ownership and operation of PIPP including different alternatives for the joint venture with Wolverine. Ultimately, in December 2013, the parties decided to terminate the joint venture. We are currently evaluating options for the long-term future of PIPP, including the potential sale of the plant. At the same time, we are analyzing several environmental compliance options at PIPP.
The new standard may also require us to make modifications at some of our smaller generation units.

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

Mercury and Other Hazardous Air Pollutants:   In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric generating units. We currently anticipate that only PIPP will require modifications, and are currently evaluating several available options for PIPP to comply with MATS. In April 2013, we received a one year MATS compliance extension through April 16, 2016 from the MDEQ.
In January 2013, the EPA issued the National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Industrial Boiler MACT Rule). The Industrial Boiler MACT rule imposes stringent limitations on numerous hazardous air pollutants from large boilers that do not meet the definition of electric generating units. The compliance date set forth in the rule is January 31, 2016, but a one year extension of that deadline may be available where emission controls cannot be installed and operational by the compliance date. Along with some smaller gas fired boilers in our fleet, the boilers at the Milwaukee County Power Plant (MCPP) are subject to this rule. We are currently evaluating compliance options for the three coal fired boilers at MCPP.

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

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

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

Clean Air Visibility Rule:   The EPA issued the Clean Air Visibility Rule in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to the EPA's CAIR. The pollutants from power plants that reduce visibility include PM2.5 or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia.

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In June 2012, the EPA promulgated a Federal Implementation Plan that approves reliance on the CSAPR to satisfy electric generating unit BART requirements for 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 subsequent appeals, we will not be able to determine final regional haze requirements for NOx and SO2 at our facilities until the United States Supreme Court issues its decision and any subsequent rulemaking activities that may be required as a result of that decision have been finalized.

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

Repowered the Port Washington Power Plant from coal to natural gas-fired combined cycle units.
Added coal-fired units as part of the Oak Creek expansion that are the most thermally efficient coal units in our system.
Increased our investment in energy efficiency and conservation.
Added renewable capacity.
Planning to convert the fuel source at the VAPP from coal to natural gas.
Retired coal units 1-4 at PIPP

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

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

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

We are required to report our CO2 equivalent emissions from our electric generating facilities to the EPA under its Mandatory Reporting of Greenhouse Gases rule. For 2012, we reported CO2 equivalent emissions of approximately 18.1 million metric tonnes to the EPA, compared with approximately 22.4 million metric tonnes for 2011. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 21.9 million metric tonnes to the EPA for 2013. The level of CO2 and other greenhouse gas emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed and how our units are dispatched by MISO.

We are also required to report CO2 amounts related to the natural gas our gas utility distributes and sells. For 2012, we reported approximately 3.3 million metric tonnes of CO2 to the EPA related to our distribution and sale of natural gas, compared with approximately 3.8 million metric tonnes for 2011. Based upon our preliminary analysis of the

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monitoring data, we estimate that we will report CO2 emissions of approximately 4.1 million metric tonnes to the EPA for 2013.

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

In June 2012, we received approval from the PSCW to replace and upgrade the Lincoln Arthur natural gas main, which has the capability to accommodate the increased natural gas required for the conversion of VAPP to natural gas. Construction began on the Lincoln Arthur natural gas main in March 2013. For further information, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.

Water Quality

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

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

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

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

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

In December, 2012, the WDNR issued a new Wisconsin Pollutant Discharge Elimination System (WPDES) permit for VAPP that became effective on January 1, 2013. The new permit includes significant new immediate and long-term permit requirements. Effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges all took effect immediately. Longer term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and redesign of the cooling water intakes to minimize impingement impacts to aquatic organisms.

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

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our facility permits. The rule compliance deadline is as soon as possible after July 1, 2017 with full compliance expected by July 1, 2022. We already meet many of the proposed requirements defined by the EPA, and as a result believe we will be well positioned to comply with the proposed guidelines. There are several available options outlined in the proposed rule. The amount of additional costs we may need to incur to comply with the new guidelines, if any, will depend on which option(s) the EPA selects to incorporate into the final guidelines. Until the rules are finalized, we are unable to determine the impact on our facilities.

Land Quality

Proposed New Coal Combustion Products Regulation:   We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Both Wisconsin and Michigan have regulations governing the use and disposal of these materials. In 2010, the EPA issued draft rules for public comment proposing two alternative rules for regulating coal combustion products, one of which would classify the materials as hazardous waste. We anticipate that the EPA could take action on a final rule by the end of 2014. If coal combustion products are classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program.

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

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

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

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


LEGAL MATTERS

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

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



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INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

The regulated energy industry continues to experience significant changes. The 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, Michigan has adopted retail choice.Wisconsin.


2016 Form 10-K42Wisconsin Electric Power Company
Table of Contents

Restructuring in Wisconsin:Wisconsin

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

Restructuring in Michigan:   UnderMichigan

During 2016, under Michigan law, our retail customers mayhad the option to choose an alternative electric supplier to provide power supply service. Theservice, and some of our small retail customers elected to use this option. We, however, still provided distribution and customer service functions for these customers. As of December 31, 2016, the law limitslimited customer choice to 10% of our Michigan retail load. The twoload, but this cap excludes the iron ore mines are excluded from this cap. When a customer switches to an alternative electric supplier,mine owned by Tilden Mining Company (Tilden) that was in our service territory.

Effective January 1, 2017, we continue to provide distribution and customer service functions for the customer.
The mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers have switched to an alternative electric supplier. Sales to these customers, including the mines, totaled 2,173.6 GWh, or 7.6%transferred all of our retail electric sales for the year ended December 31, 2012. Previously, the owner of the mines announced that they would shut down the Empire mine by the end of 2014 or beginning of 2015.

We have taken,distribution assets and will continue to take, multiple steps to mitigate these impacts in 2014 and going forward. In August 2013, we filed a request with MISO to suspend the operation of all five units at PIPP. In October 2013, MISO informed us that the operation of all units is necessary to maintain reliabilitycustomers located in the Upper Peninsula of Michigan. On January 30, 2014, we entered into a SSR Agreement with MISOMichigan to recover costs for operating and maintaining the units. The Agreement is effective February 1, 2014, has a one year term, and specifies monthly payments of $4.4 million to cover fixed costs. The Agreement also provides for the payment of our variable costs to operate and maintain the plant. MISO filed the SSR Agreement at FERC on January 31, 2014 and is requesting FERC's approval of this Agreement.

In addition, we filed an applicationUMERC, with the MPSC requesting authority to defer all fixed production costs that would have been recovered from the customers who switched to an alternative electric supplier. In August 2013, the MPSC issued an order approving the deferralexception of costs allocable to our remaining Michigan retail customers. In September 2013, we filed a petitionTilden. See Note 4, Related Parties, andNote 20, Regulatory Environment, for re-hearing with the MPSC requesting reconsideration of its deferral order; however, our request was denied. Our ability to collect the deferred costs will be determined in a subsequent rate proceeding.

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

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

Electric Transmission, Capacity and Energy Markets

In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which includes the bid-based energy markets and an ancillary services market. We previously self-provided both

61Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K

regulation reserves and contingency reserves. In the MISO ancillary services market, we buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market has been able to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

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

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

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through Auction Revenue Rights (ARRs) and Financial Transmission Rights (FTRs). ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2013 through May 31, 2014. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

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

Natural Gas Utility Industry

We offer natural gas transportation services to our customers that elect to purchase natural gas from an alternative retail natural gas supplier. Since these transportation customers continue to use our distribution systems to transport the natural gas to their facilities, we earn distribution revenues from them. As such, the loss of revenue associated with the natural gas that transportation customers purchase from an alternative retail natural gas supplier has little impact on our net income, since it is offset by an equal reduction to natural gas costs.

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 inprovide customer segmentsclasses with workably competitive market choices andthe option to choose an alternative retail natural gas supplier. The PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates. However, work on deregulationAll of theour Wisconsin customer classes have workably competitive market choices and, therefore, can purchase natural gas distribution industry by the PSCW continues to be on hold.directly from either an alternative retail natural gas supplier or their local natural gas utility. Currently, we are unable to predict the impact of potential future deregulationindustry restructuring on our results of operations or financial position.


OTHER MATTERSEnvironmental Matters

Oak Creek Expansion Fuel Flexibility Project:See Note 16, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

American Transmission Company Allowed Return On Equity Complaints

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, from 12.2% to 9.15%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision recommending 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 Oak Creek expansion units were designed and permittedincentive adder only applies to use bituminous coal fromrevenues collected after January 6, 2015. In September 2016, the Eastern United States. Market forces have resulted inFERC issued a significant price differential between bituminous and sub-bituminous coals. We received a new air construction permit fromfinal order related to this complaint affirming the WDNR to modify the Oak Creek expansion units for potential future use of sub-bituminous coal. In May 2013, we began testing various combinations of sub-bituminous coal and bituminous coal to identify any equipment limitations that should be considered prior to filing with the PSCW for a Certificate of Authority to make any fuel flexibility modifications. In February 2013,ROEs stated in the Sierra Club and the Midwest Environmental Defense Center filed a petition for a contested case hearing with the WDNR to challenge the issuanceALJ's initial decision, effective as of the air construction permit.order date, on a going-forward basis. The WDNR has granted that petition, but a hearing has not yet been scheduled.order also requires ATC to provide refunds, with interest, for the 15-month refund period from November 13, 2013, through February 11, 2015. As of December 31, 2016, ATC had started to provide refunds to us for transmission costs paid during the refund period, and we expect the refund process to be completed by July 2017. As these refunds are received, we reduce the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense.

Paris Generating Station Units 1 and 4 Temporary Outage: Between 2000 and 2002, we replaced the blades on the four PSGS combustion turbine generators with blades that were approximately 7% more efficient. Although the work was performed as routine maintenance that we did not believe required a construction permit at the time and the plant has not been operated to use the potential additional capacity, the WDNR has indicated that it now considers this maintenance to be a modification requiring a construction permit. The WDNR issued a NOV to us on January 7, 2013 alleging violations of the new source review rules and certain Wisconsin environmental rules. At the same time, the WDNR also issued an administrative order that prohibits us from operating PSGS Units 1 and 4 until the earlier of: (1) Units 1 and 4 achieve the applicable NOx emission rates; (2) the Wisconsin regulations are

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


revised soIn 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 February 12, 2015. In June 2016, the ALJ issued an initial decision recommending that Units 1ATC and 4 can achieveall other MISO transmission owners be authorized to collect a base ROE of 9.7%, as well as the emission limits or are no longer subject0.5% incentive adder approved for MISO transmission owners. The ALJ's initial decision is not binding on the FERC and applies to the limits; (3) the alleged modification is resolvedrevenues collected from February 12, 2015, through a consent decree; or (4) a court decides that the blade replacement project was not a major modification.May 11, 2016. We are presently evaluating alternative approachesnot certain when a FERC order related to return these peaking unitsthis matter will be issued.

MISO transmission owners have filed various appeals related to service, and expect Units 1 and 4 to remain out of service until at least the endseveral of the secondquarterFERC orders with the D.C. Circuit Court of 2014. In December 2013,Appeals as well as requests for rehearing.

Bonus Depreciation Provisions

The Protecting Americans from Tax Hikes Act 91of 2015 was signed into law on December 18, 2015. This act extended 50% bonus depreciation to assets placed in Wisconsin, creating a process by which the EPAservice during 2015 through 2017, 40% bonus depreciation to assets placed in service during 2018, and WDNR may revise the regulations applicable30% bonus depreciation to Units 1 and 4 and allow those units to restart.
In February 2013, the Sierra Club filed for a contested case hearing with the WDNRassets placed in connection with the administrative order. The WDNR has grantedservice during 2019. Bonus depreciation is an additional amount of tax deductible depreciation that petition, but a hearing has not yet been scheduled. In addition, in May 2013, the WDNR referred the matteris awarded above what would normally be available. Due to the Wisconsin Department of Justiceresulting increase in federal tax depreciation, we did not make federal income tax payments for alleged violations of air management statutes and rules. We could be subject to fines and penalties.
PSGS Units 2 and 3 remain available for operation, because the turbine blade maintenance on these units occurred prior to a rule change in 2001.2016.


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.

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

During 2013, we recognized the Treasury Grant as income, less the amounts that we have established as a deferred liability. The amount reflected in earnings matched the amount of the bill credits given to customers. The deferred balance reflects the amount of the grant income that we expect to benefit our customers in the future. This accounting reflects the regulatory treatment of the grant.
The PSCW approved escrow accounting treatment for the Treasury Grant. Under escrow accounting, we true-up any differences between the actual grant proceeds receivedPolicies and the grant proceeds passed on to customers in the form of bill credits.
Tangible Property Regulations:   During September 2013, the Treasury Department and IRS issued final regulations pertaining to costs incurred to acquire, maintain or improve tangible property. These regulations are generally effective for tax years beginning on or after January 1, 2014. We continue to evaluate what impact, if any, the adoption of the regulations will have on our consolidated financial statements; however, we do not currently expect the impact to be material.

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


63Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2013 Form 10-K

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, 2013, we had $1,370.3 million in regulatory assets and $634.2 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-contributory defined pension benefits (describedand OPEB, described in Note N --15, Employee Benefits, in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of 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. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

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

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

Pension Plan Impact on
Actuarial Assumption Annual Cost
  (Millions of Dollars)
   
0.5% decrease in discount rate and lump sum conversion rate $4.8
0.5% decrease in expected rate of return on plan assets $5.3

In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note N -- Benefits in the Notes to Consolidated Financial Statements). Our reported costs of providing these post-retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee demographics (age and compensation levels), our contributions to the plans, earnings on plan assets and health care cost trends. Changes made to the provisions of the plans may also impact current and future OPEB costs. OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and the discount rates, used in determiningand expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

Pension 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.We believe that such changes in costs would be recovered or refunded through the ratemaking process.


2016 Form 10-K6444Wisconsin Electric Power Company
Table of Contents

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 2016
Pension Cost
Discount rate (0.5) $68.4
 $4.8
Discount rate 0.5 (59.3) (3.9)
Rate of return on plan assets (0.5) N/A
 5.6
Rate of return on plan assets 0.5 N/A
 (5.6)

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 2016 Postretirement
Benefit Cost
Discount rate (0.5) $21.6
 $0.6
Discount rate 0.5 (18.6) (0.5)
Health care cost trend rate (0.5) (13.4) (1.2)
Health care cost trend rate 0.5 15.2
 1.4
Rate of return on plan assets (0.5) N/A
 1.0
Rate of return on plan assets 0.5 N/A
 (1.0)

The discount rates are selected based on hypothetical bond portfolios consisting of noncallable (or callable with make-whole provisions), noncollateralized, high-quality corporate bonds across the full maturity spectrum. 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 2016 and 2015, and 7.25% in 2014. The actual rate of return on pension plan assets, net of fees, was 6.91%, (0.6)%, and 6.17%, in 2016, 2015, and 2014, 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 15, Employee Benefits.

Regulatory Accounting

Our utility operations 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 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 from our utility operations, 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 utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be 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, 2016, we had $2,036.6 million in regulatory assets and $864.1 million in regulatory liabilities. See Note 7, Regulatory Assets and Liabilities, for more information.


ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)20132016 Form 10-K45Wisconsin Electric Power Company

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

OPEB Plan Impact on
Actuarial Assumption Annual Cost
  (Millions of Dollars)
   
0.5% decrease in discount rate $0.7
0.5% decrease in health care cost trend rate in all future years $(1.4)
0.5% decrease in expected rate of return on plan assets $1.0
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 20132016 of approximately $3.8$3.8 billion included accrued revenues of $240.7$211.4 million as of December 31, 2013.2016.

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 14, 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 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -– Factors Affecting Results, Liquidity, and Capital Resources --– Market Risks and Other Significant Risks, in Item 7 of this report, as well as Note L -- Derivative Instruments and Note M --1(n), Fair Value Measurements in the Notes to Consolidated Financial Statements,, and
Note 1(o), Derivative Instruments, for information concerning potential market risks to which we are exposed.


2016 Form 10-K6546Wisconsin Electric Power Company
Table of Contents
2013 Form 10-K


ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
Year Ended December 31
      
 2013 2012 2011
 (Millions of Dollars)
      
Operating Revenues$3,800.2
 $3,613.3
 $3,727.6
      
Operating Expenses     
Fuel and purchased power1,158.1
 1,103.8
 1,174.5
Cost of gas sold278.3
 227.7
 306.2
Other operation and maintenance1,417.3
 1,327.8
 1,447.6
Depreciation and amortization278.6
 257.6
 220.3
Property and revenue taxes110.0
 113.1
 105.4
Total Operating Expenses3,242.3
 3,030.0
 3,254.0
      
Treasury Grant48.0
 —
 —
      
Operating Income605.9
 583.3
 473.6
      
Equity in Earnings of Transmission Affiliate60.2
 57.6
 54.9
Other Income and Deductions, net17.4
 32.3
 62.1
Interest Expense, net121.4
 113.2
 94.2
      
Income Before Income Taxes562.1
 560.0
 496.4
      
Income Tax Expense200.9
 192.7
 156.8
      
Net Income361.2
 367.3
 339.6
      
Preferred Stock Dividend Requirement1.2
 1.2
 1.2
      
Earnings Available for Common Stockholder$360.0
 $366.1
 $338.4
      
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



66Wisconsin Electric Power Company
2013 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
 
ASSETS
    
 2013 2012
 (Millions of Dollars)
Property, Plant and Equipment   
Electric$8,717.0
 $8,171.0
Gas977.4
 950.3
Steam102.0
 95.5
Common307.4
 295.3
Other56.8
 56.8
 10,160.6
 9,568.9
Accumulated depreciation(3,258.8) (3,117.0)
 6,901.8
 6,451.9
Construction work in progress101.9
 289.1
Leased facilities, net2,279.0
 2,340.2
Net Property, Plant and Equipment9,282.7
 9,081.2
    
Investments   
Equity investment in transmission affiliate354.1
 332.6
Other0.2
 0.3
Total Investments354.3
 332.9
    
Current Assets   
Cash and cash equivalents25.1
 34.1
Accounts receivable, net of allowance for   
doubtful accounts of $39.7 and $36.7335.7
 226.3
Accounts receivable from related parties9.1
 6.1
Accrued revenues240.7
 213.8
Materials, supplies and inventories281.0
 312.2
Current deferred tax asset, net75.8
 4.1
Prepayments137.7
 136.3
Other8.7
 32.1
Total Current Assets1,113.8
 965.0
    
Deferred Charges and Other Assets   
Regulatory assets1,370.3
 1,481.2
Other164.5
 162.3
Total Deferred Charges and Other Assets1,534.8
 1,643.5
    
Total Assets$12,285.6
 $12,022.6
    
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.


67Wisconsin Electric Power Company
2013 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
 
CAPITALIZATION AND LIABILITIES
    
 2013 2012
 (Millions of Dollars)
Capitalization   
Common equity$3,406.8
 $3,366.4
Preferred stock30.4
 30.4
Long-term debt2,167.3
 2,216.7
Capital lease obligations2,712.0
 2,703.1
Total Capitalization8,316.5
 8,316.6
    
Current Liabilities   
Long-term debt and capital lease obligations due currently379.5
 357.0
Short-term debt174.5
 105.5
Subsidiary note payable to Wisconsin Energy22.8
 23.4
Accounts payable273.8
 306.8
Accounts payable to related parties85.9
 93.4
Accrued payroll and benefits89.3
 75.4
Other132.3
 108.7
Total Current Liabilities1,158.1
 1,070.2
    
Deferred Credits and Other Liabilities   
Regulatory liabilities634.2
 601.8
Deferred income taxes - long-term1,794.5
 1,533.6
Pension and other benefit obligations160.1
 189.2
Other222.2
 311.2
Total Deferred Credits and Other Liabilities2,811.0
 2,635.8
    
Commitments and Contingencies (Note Q)
 
    
Total Capitalization and Liabilities$12,285.6
 $12,022.6
    
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



68Wisconsin Electric Power Company
2013 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
       
  2013 2012 2011
  (Millions of Dollars)
Operating Activities      
Net income $361.2
 $367.3
 $339.6
Reconciliation to cash      
Depreciation and amortization 288.3
 263.6
 223.6
Deferred income taxes and investment tax credits, net 193.6
 194.1
 265.1
Contributions to qualified benefit plans —
 (92.9) (275.1)
Change in - Accounts receivable and accrued revenues (137.0) 64.3
 (9.0)
Inventories 31.2
 7.0
 2.6
Other current assets 0.7
 6.9
 (23.5)
Accounts payable (29.4) 41.4
 41.4
Accrued income taxes, net 23.6
 89.4
 (85.4)
Deferred costs, net (8.7) 9.2
 25.9
Other current liabilities 21.8
 (2.4) 23.9
Other, net 117.3
 (140.9) 14.8
Cash Provided by Operating Activities 862.6
 807.0
 543.9
       
Investing Activities      
Capital expenditures (506.9) (575.8) (706.6)
Investment in transmission affiliate (9.2) (13.8) (5.8)
Proceeds from asset sales 2.5
 3.3
 41.5
Change in restricted cash 2.7
 42.8
 (37.2)
Cost of removal, net of salvage (32.0) (32.9) (12.5)
Other, net (17.2) (29.2) (41.5)
Cash Used in Investing Activities (560.1) (605.6) (762.1)
       
Financing Activities      
Dividends paid on common stock (340.0) (179.6) (239.6)
Dividends paid on preferred stock (1.2) (1.2) (1.2)
Issuance of long-term debt 250.0
 250.0
 300.0
Retirement of long-term debt (300.0) —
 —
Change in total short-term debt 68.4
 (249.9) 140.7
Other, net 11.3
 0.7
 7.7
Cash (Used In) Provided by Financing Activities (311.5) (180.0) 207.6
       
Change in Cash and Cash Equivalents (9.0) 21.4
 (10.6)
       
Cash and Cash Equivalents at Beginning of Year 34.1
 12.7
 23.3
       
Cash and Cash Equivalents at End of Year $25.1
 $34.1
 $12.7
       
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.


69Wisconsin Electric Power Company
2013 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
     
  2013 2012
  (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 capital965.1
 944.7
Retained earnings2,108.8
 2,088.8
Total Common Equity3,406.8
 3,366.4
     
Preferred Stock (Note I)30.4
 30.4
     
Long-Term Debt    
Debentures (unsecured)4.50% due 2013—
 300.0
 6.00% due 2014300.0
 300.0
 6.25% due 2015250.0
 250.0
 1.70% due 2018250.0
 —
 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
 250.0
 6-7/8% due 2095100.0
 100.0
     
Note (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 J)(147.0) (147.0)
Unamortized discount, net (19.7) (20.3)
Long-term debt due currently (300.0) (300.0)
Total Long-Term Debt 2,167.3
 2,216.7
     
Obligations Under Capital Leases (see Note J)2,712.0
 2,703.1
     
Total Capitalization $8,316.5
 $8,316.6
     

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

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

70Wisconsin Electric Power Company
2013 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, 2010$332.9
 $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, 2012332.9
 944.7
 2,088.8
 3,366.4
Net income    361.2
 361.2
Cash dividends       
Common stock    (340.0) (340.0)
Preferred stock    (1.2) (1.2)
Stock-based compensation  3.7
   3.7
Tax benefit of exercised stock options allocated from Parent  16.7
   16.7
Balance - December 31, 2013$332.9
 $965.1
 $2,108.8
 $3,406.8
        
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



71Wisconsin Electric Power Company
2013 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 $29.1 million and $30.2 million as of December 31, 2013 and 2012, 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:   We have adjusted the presentation of regulatory assets and liabilities to present amounts as noncurrent assets and liabilities on the consolidated balance sheets. Prior period amounts recorded within other current assets and liabilities have been reclassified to conform to the current presentation. For additional information related to regulatory assets and liabilities, see Note C.

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

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

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

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

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

Other Income and Deductions, net 2013 2012 2011
  (Millions of Dollars)
       
AFUDC - Equity $17.6
 $34.9
 $59.2
Other, net (0.2) (2.6) 2.9
Total Other Income and Deductions, net $17.4
 $32.3
 $62.1

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

72Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.9% in 2013, 2012and2011.

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 $558.9 million as of December 31, 2013 and $561.3 million as of December 31, 2012.

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:

  2013 2012 2011
  (Millions of Dollars)
       
AFUDC - Debt $7.4
 $14.5
 $24.7
AFUDC - Equity $17.6
 $34.9
 $59.2

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

Materials, Supplies and Inventories 2013 2012
  (Millions of Dollars)
     
Fossil Fuel $117.5
 $165.3
Materials and Supplies 129.5
 118.6
Natural Gas in Storage 34.0
 28.3
Total $281.0
 $312.2

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. 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)2013 Form 10-K

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

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

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

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, 2013 and 2012. We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note P.

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

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)2013 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:

 2013 2012 2011
Risk-free interest rate0.1% - 1.9% 0.1% - 2.0% 0.2% - 3.4%
Dividend yield3.7% 3.9% 3.9%
Expected volatility18.0% 19.0% 19.0%
Expected life (years)5.9 5.9 5.5
Expected forfeiture rate2.0% 2.0% 2.0%
Weighted-average fair value     
of stock options granted$3.45 $3.34 $3.17

Treasury Grant:   In December 2013, we filed an application with the United States Treasury for a Section 1603 renewable energy grant related to the construction of our biomass facility in Rothschild, Wisconsin. The PSCW anticipated the recognition of this grant as income when it set rates for the two years beginning January 1, 2013. We provided bill credits to our customers in 2013, and this will continue into 2014. As of December 31, 2013, $48.0 million was recognized as income, which reflects the amount that was returned to customers in the form of bill credits during the year. We recorded an $82.6 million receivable, and deferred the balance that we expect to benefit our customers in the future. The accounting reflects the regulatory treatment of the grant.

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


B -- RECENT ACCOUNTING PRONOUNCEMENTS

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


C -- REGULATORY ASSETS AND LIABILITIES

Our primary regulator, the PSCW, considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon orders or correspondence with our regulators. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2013, we had $8.6 million of regulatory assets not earning a return and $82.7 million of regulatory assets earning a return based on short-term interest rates.


75Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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

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

  2013 2012
  (Millions of Dollars)
Regulatory Assets    
Deferred plant related -- capital leases $512.5
 $419.8
Deferred unrecognized pension costs 393.0
 555.0
Deferred income tax related 165.8
 173.1
Escrowed electric transmission costs 126.8
 114.1
Other, net 172.2
 219.2
Total regulatory assets $1,370.3
 $1,481.2
     
Regulatory Liabilities    
Deferred cost of removal obligations $558.9
 $561.3
Other, net 75.3
 40.5
Total regulatory liabilities $634.2
 $601.8

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


D -- 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

AROs have been recorded for asbestos abatement at certain generation and substation facilities, and for obligations associated with the removal and dismantlement of generation facilities. AROs are recorded in other long-term liabilities on the Consolidated Balance Sheets. The following table presents the change in our AROs during 2013 and 2012:

  2013 2012
  (Millions of Dollars)
     
Balance as of January 1 $41.5
 $52.9
Liabilities Settled (4.3) (14.0)
Accretion 2.2
 2.6
Balance as of December 31 $39.4
 $41.5



76Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

F -- VARIABLE INTEREST ENTITIES

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

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

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

We have approximately $215.9 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under contracts considered variable interests in 2013, 2012 and 2011 were $50.3 million, $45.8 million and $65.9 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.


G -- INCOME TAXES

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

Income Taxes 2013 2012 2011
  (Millions of Dollars)
       
Current tax expense (benefit) $7.3
 $(1.4) $(108.3)
Deferred income taxes, net 194.7
 195.2
 269.0
Investment tax credit, net (1.1) (1.1) (3.9)
Total Income Tax Expense $200.9
 $192.7
 $156.8

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:

  2013 2012 2011
    Effective   Effective   Effective
Income Tax Expense Amount Tax Rate Amount Tax Rate Amount Tax Rate
  (Millions of Dollars)
             
Expected tax at statutory federal tax rates $196.3
 35.0 % $195.6
 35.0 % $173.3
 35.0 %
State income taxes net of federal tax benefit 31.7
 5.6 % 28.8
 5.1 % 25.9
 5.2 %
Production tax credits - wind (16.7) (3.0)% (15.9) (2.8)% (8.7) (1.8)%
Treasury Grant (7.4) (1.3)% —
 — % —
 — %
AFUDC - Equity (6.1) (1.1)% (12.2) (2.2)% (20.7) (4.2)%
Investment tax credit restored (1.1) (0.2)% (1.1) (0.2)% (3.9) (0.8)%
Domestic production activities deduction —
 — % (12.6) (2.3)% (12.6) (2.5)%
Other, net 4.2
 0.7 % 10.1
 1.8 % 3.5
 0.7 %
Total Income Tax Expense $200.9
 35.7 % $192.7
 34.4 % $156.8
 31.6 %

77Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 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 2013 2012
  (Millions of Dollars)
Current    
Future federal tax benefits $113.1
 $—
Uncollectible account expense 17.2
 17.4
Employee benefits and compensation 11.7
 12.6
Recoverable gas costs 0.5
 0.4
Other 3.3
 22.4
Total Current Deferred Tax Assets 145.8
 52.8
     
Non-current    
Deferred revenues 237.0
 250.0
Employee benefits and compensation 92.4
 92.3
Construction advances 15.0
 19.1
Future federal tax benefits —
 118.1
Other 42.2
 3.8
Total Non-Current Deferred Tax Assets 386.6
 483.3
Total Deferred Tax Assets $532.4
 $536.1
Deferred Tax Liabilities 2013 2012
  (Millions of Dollars)
Current    
Prepaid items $70.0
 $48.7
Total Current Deferred Tax Liabilities 70.0
 48.7
     
Non-current    
Property-related 1,820.9
 1,639.5
Investment in transmission affiliate 147.8
 125.9
Employee benefits and compensation 135.0
 145.0
Deferred transmission costs 50.8
 45.7
Other 26.6
 60.8
Total Non-current Deferred Tax Liabilities 2,181.1
 2,016.9
Total Deferred Tax Liabilities $2,251.1
 $2,065.6
     
Consolidated Balance Sheet Presentation 2013 2012
Current Deferred Tax Asset $75.8
 $4.1
Non-Current Deferred Tax Liability $1,794.5
 $1,533.6

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

As of December 31, 2013, we had approximately $216.8 million and $37.2 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of approximately $75.9 million and $37.2 million, respectively. 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. 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)2013 Form 10-K

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

 2013 2012
 (Millions of Dollars)
    
Balance as of January 1$10.8
 $10.6
Additions for tax positions of prior years—
 10.8
Reductions for tax positions of prior years(2.4) (10.6)
Balance as of December 31$8.4
 $10.8

The amount of unrecognized tax benefits as of December 31, 2013 and 2012 excludes deferred tax assets related to uncertainty in income taxes of $8.4 millionand$9.8 million, respectively. As of December 31, 2013 and 2012, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was zero and $0.9 million, 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, 2013, 2012 and 2011, we recognized approximately $0.2 million, $0.2 million and $0.6 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2013, 2012 and 2011, we recognized no penalties in the Consolidated Income Statements. We had approximately $0.4 million and $0.2 million of interest accrued in the Consolidated Balance Sheets as of December 31, 2013 and 2012, respectively.

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

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


H -- COMMON EQUITY

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

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

  2013 2012 2011
  (Millions of Dollars)
       
Performance units $11.9
 $14.2
 $20.3
Stock options 3.8
 2.6
 2.5
Restricted stock 1.6
 2.0
 1.1
Share-based compensation expense $17.3
 $18.8
 $23.9
       
Related Tax Benefit $6.9
 $7.5
 $9.6

79Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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

The following is a summary of Wisconsin Energy stock option activity by our employees during 2013:

      Weighted-Average  
    Weighted- Remaining Aggregate
  Number of Average Contractual Life Intrinsic Value
Stock Options Options Exercise Price (Years) (Millions)
Outstanding as of January 1, 2013 8,416,876
 $23.96
    
Granted 1,365,970
 $37.46
    
Exercised (2,083,973) $21.84
    
Forfeited (10,030) $35.37
    
Outstanding as of December 31, 2013 7,688,843
 $26.92
 5.4 $110.9
         
Exercisable as of December 31, 2013 5,399,443
 $23.21
 4.1 $97.9

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

In January 2014, the Compensation Committee of the Board of Directors of Wisconsin Energy (Compensation Committee) awarded 866,805 Wisconsin Energy non-qualified stock options with an exercise price of $41.03 to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

The intrinsic value of Wisconsin Energy options exercised during the years ended December 31, 2013, 2012 and 2011 was $41.2 million, $42.9 million and $31.8 million, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $45.5 million, $45.4 million and $49.3 million during the years ended December 31, 2013, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $16.6 million, zero and $9.7 million, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of December 31, 2013:

  Options Outstanding Options Exercisable
    Weighted-Average   Weighted-Average
      Remaining     Remaining
  Number of Exercise Contractual Number of Exercise Contractual
Range of Exercise Prices Options Price  Life (Years) Options Price  Life (Years)
$16.72  to  $21.11 1,967,798
 $20.37 3.9 1,967,798
 $20.37 3.9
$23.88  to  $29.35 3,533,700
 $24.66 4.2 3,240,440
 $24.23 4.0
$34.88  to  $37.46 2,187,345
 $36.48 8.6 191,205
 $35.14 8.1
             
  7,688,843
 $26.92 5.4 5,399,443
 $23.21 4.1


80Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

The following table summarizes information about non-vested Wisconsin Energy options held by our employees during 2013:

  Number of 
Weighted-
Average
Non-Vested Stock Options Options  Fair Value
     
Non-Vested as of January 1, 2013 1,637,570
 $3.31
Granted 1,365,970
 $3.45
Vested (704,110) $3.33
Forfeited (10,030) $3.37
Non-Vested as of December 31, 2013 2,289,400
 $3.38

As of December 31, 2013, total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $2.0 million, which is expected to be recognized over the next 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 2013:

  Number of 
Weighted-
Average
Market
Restricted Shares Shares Price
Outstanding as of January 1, 2013 126,392
  
Granted 53,055
 $37.71
Released (67,722) $26.77
Forfeited (13,499) $33.30
Outstanding as of December 31, 2013 98,226
  
In January 2014, the Compensation Committee awarded 51,990 restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and one-third of the award vests on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders.

Wisconsin Energy records the market value of the restricted stock awards on the date of grant. We then amortize our share of allocated expense over the vesting period of the awards. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was $2.8 million, $2.2 million and $1.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $1.1 million, zero and $0.6 million, respectively.

As of December 31, 2013, 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 20 months on a weighted-average basis.

Performance Units:   In January 2013, 2012 and 2011, the Compensation Committee awarded 230,245, 333,685 and 413,990 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, 2013, 2012 and 2011 vested and were settled during the first quarter of 2014, 2013 and 2012, and had a total intrinsic value of $13.1 million, $17.1 million and $23.8 million, respectively. The awards were subsequently distributed to our officers and key employees in January 2013, 2012 and 2011. The actual tax benefit

81Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

realized for the tax deductions from the distribution of performance units was approximately $4.7 million, $6.2 million and $9.6 million, respectively. As of December 31, 2013, total compensation cost related to performance units not yet recognized was approximately $9.4 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

In January 2014, the Compensation Committee awarded 225,240 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 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. 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 K for discussion of certain financial covenants related to our bank back-up credit facility.

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


I -- PREFERRED STOCK

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

  Shares Authorized Shares Outstanding Redemption Price Per Share Total
        (In Millions)
$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



82Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

J -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

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

 (Millions of Dollars)
  
2014$300.0
2015250.0
2016—
2017—
2018250.0
Thereafter1,687.0
Total$2,487.0

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

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147.0 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2013 and 2012, the repurchased bonds were still outstanding, but were not reported 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 $681.5 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 $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 $644.7 million as of December 31, 2013, and will decrease to zero over the remaining lives of the contracts.


83Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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 $1,991.1 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 $529.0 million in the year 2029 for OC 1 and to approximately $439.5 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 $2,042.5 million as of December 31, 2013, and will decrease to zero over the remaining life of the contracts.

We paid the following lease payments during 2013, 2012 and 2011:

  2013 2012 2011
  (Millions of Dollars)
       
Long-term power purchase commitment $33.7
 $32.5
 $31.3
PWGS  99.1
 99.0
 97.5
Oak Creek Expansion 274.9
 269.3
 266.1
Total $407.7
 $400.8
 $394.9

The following table summarizes our capitalized leased facilities as of December 31:
Capital Lease Assets 2013 2012
  (Millions of Dollars)
     
Long-term Power Purchase Commitment    
Under capital lease $140.3
 $140.3
Accumulated amortization (92.5) (86.8)
Total Long-term Power Purchase Commitment $47.8
 $53.5
     
PWGS     
Under capital lease $681.5
 $681.0
Accumulated amortization (190.1) (162.6)
Total PWGS  $491.4
 $518.4
     
Oak Creek Expansion    
Under capital lease $1,991.1
 $1,954.0
Accumulated amortization (251.3) (185.7)
Total Oak Creek $1,739.8
 $1,768.3
     
Total Leased Facilities $2,279.0
 $2,340.2

84Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 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, 2013 are as follows:

  Power      
  Purchase   Oak Creek  
Capital Lease Obligations Commitment PWGS Expansion Total
  (Millions of Dollars)
         
2014 $41.9
 $99.1
 $275.0
 $416.0
2015 43.5
 99.1
 291.3
 433.9
2016 45.1
 99.1
 305.8
 450.0
2017 13.9
 99.1
 306.2
 419.2
2018 14.7
 99.1
 306.2
 420.0
Thereafter 56.8
 1,282.4
 6,592.0
 7,931.2
Total Minimum Lease Payments 215.9
 1,777.9
 8,076.5
 10,070.3
Less:  Estimated Executory Costs (61.7) —
 —
 (61.7)
Net Minimum Lease Payments 154.2
 1,777.9
 8,076.5
 10,008.6
Less:  Interest (49.9) (1,133.2) (6,034.0) (7,217.1)
Present Value of Net        
Minimum Lease Payments 104.3
 644.7
 2,042.5
 2,791.5
Less:  Due Currently (19.8) (8.8) (50.9) (79.5)
Total Capital Lease Obligations $84.5
 $635.9
 $1,991.6
 $2,712.0


K -- SHORT-TERM DEBT

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

  2013 2012
    Interest   Interest
  Balance Rate Balance Rate
  (Millions of Dollars, except for percentages)
         
Commercial paper $174.5 0.22% $105.5 0.27%

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

  2013 2012
  (Millions of Dollars, except for percentages)
     
Maximum Commercial Paper Outstanding $354.5
 $382.0
Average Commercial Paper Outstanding $98.0
 $251.6
Weighted-Average Interest Rate 0.22% 0.26%

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, 2013, we had approximately $493.9 million of available, undrawn lines under our bank back-up credit facility and $174.5 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, 2013, our subsidiary had a $22.8 million note payable to Wisconsin Energy with a weighted-average interest rate of 6.21%.


85Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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

As of December 31, 2013, we were in compliance with all financial covenants.


L -- DERIVATIVE INSTRUMENTS

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

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of December 31, 2013, we recognized $0.3 million in regulatory assets and $8.1 million in regulatory liabilities related to derivatives in comparison to $3.7 million in regulatory assets and $16.7 million in regulatory liabilities as of December 31, 2012.

We record our current derivative assets on the balance sheet in other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $0.4 million is recorded in other deferred charges and other assets, and we had no long-term portion of derivative liabilities. Our Consolidated Balance Sheets as of December 31, 2013 and 2012 include:

  December 31, 2013 December 31, 2012
  
Derivative
Asset
 
Derivative
Liability
 
Derivative
Asset
 
Derivative
Liability
  (Millions of Dollars)
Natural Gas $2.8
 $0.1
 $1.2
 $1.1
Fuel Oil 0.6
 —
 0.4
 —
FTRs 3.5
 —
 4.7
 —
Coal 2.1
 0.2
 11.1
 —
Total $9.0
 $0.3
 $17.4
 $1.1

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, 2013 and 2012 were as follows:

  2013 2012
  Volume Gains (Losses) Volume Gains (Losses)
    (Millions of Dollars)   (Millions of Dollars)
Natural Gas 24.0 million Dth $(4.0) 38.9 million Dth $(16.4)
Fuel Oil 8.6 million gallons 0.5
 7.0 million gallons 1.8
FTRs 25.3 million MWh 14.9
 25.1 million MWh 6.1
Total   $11.4
   $(8.5)

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

The fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same

86Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

counterparty under the same master netting arrangement. The table below shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet as of December 31, 2013 and 2012.

 December 31, 2013 December 31, 2012
 Derivative Derivative Derivative Derivative
 Asset Liability Asset Liability
 (Millions of Dollars)
        
Gross Amount Recognized on the Balance Sheet$9.0
 $0.3
 $17.4
 $1.1
Gross Amount Not Offset on Balance Sheet (a)—
 —
 (0.4) (1.1)
Net Amount$9.0
 $0.3
 $17.0
 $—
        

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


M -- FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is 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)2013 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, 2013
  Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
Assets:        
Derivatives $3.2
 $2.3
 $3.5
 $9.0
Total $3.2
 $2.3
 $3.5
 $9.0
Liabilities:        
Derivatives $—
 $0.3
 $—
 $0.3
Total $—
 $0.3
 $—
 $0.3

Recurring Fair Value Measures As of December 31, 2012
  Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
Assets:        
Restricted Cash $2.7
 $—
 $—
 $2.7
Derivatives 1.2
 11.5
 4.7
 17.4
Total $3.9
 $11.5
 $4.7
 $20.1
Liabilities:        
Derivatives $1.1
 $—
 $—
 $1.1
Total $1.1
 $—
 $—
 $1.1

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

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


88Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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

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

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

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

  2013 2012
  Carrying Fair Carrying Fair
Financial Instruments Amount Value Amount Value
  (Millions of Dollars)
         
Preferred stock, no redemption required $30.4
 $26.0
 $30.4
 $26.0
Long-term debt including current portion $2,487.0
 $2,634.7
 $2,537.0
 $2,900.8

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


N -- BENEFITS

Pensions and Other Post-retirement Benefits:   We participate in Wisconsin Energy's defined benefit pension plans that cover substantially all of our employees. Generally, employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Approximately half of our projected benefit obligation relates to benefits based upon years of service and final average salary.

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.


89Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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

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

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

  Pension OPEB
  2013 2012 2013 2012
  (Millions of Dollars)
Change in Benefit Obligation        
Benefit Obligation at January 1 $1,310.3
 $1,153.3
 $305.4
 $317.3
Service cost 13.9
 19.8
 9.5
 9.8
Interest cost 52.4
 56.8
 12.7
 16.7
Participants' contributions —
 —
 8.1
 9.1
Plan amendments (0.9) —
 —
 —
Inter Plan transfer —
 (0.1) —
 —
Actuarial (gain) loss (73.9) 144.3
 (22.7) (26.9)
Other accrued benefits —
 30.3
 —
 —
Gross benefits paid (78.7) (94.1) (21.3) (21.4)
Federal subsidy on benefits paid N/A
 N/A
 0.7
 0.8
Benefit Obligation at December 31 $1,223.1
 $1,310.3
 $292.4
 $305.4
         
Change in Plan Assets        
Fair Value at January 1 $1,121.1
 $1,018.1
 $194.8
 $173.9
Actual earnings on plan assets 119.0
 102.6
 30.7
 19.6
Employer contributions 7.5
 94.5
 10.1
 13.6
Participants' contributions —
 —
 8.1
 9.1
Gross benefits paid (78.7) (94.1) (21.3) (21.4)
Fair Value at December 31 $1,168.9
 $1,121.1
 $222.4
 $194.8
         
Net liability $(54.2) $(189.2) $(70.0) $(110.6)

As of December 31, 2013, our qualified pension plan was over-funded by $34.3 million and our non-qualified pension plan was under-funded by $88.5 million. As of December 31, 2012, our qualified and non-qualified pension plans were under-funded by $98.5 million and $90.7 million, respectively.

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

  Pension OPEB
  2013 2012 2013 2012
  (Millions of Dollars)
         
Other long-term assets $34.3
 $—
 $1.6
 $0.3
Other long-term liabilities $88.5
 $189.2
 $71.6
 $110.9

The accumulated benefit obligation for all defined benefit plans was $1,222.3 million and $1,309.0 million as of December 31, 2013 and 2012, respectively.


90Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 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
  2013 2012 2013 2012
  (Millions of Dollars)
         
Net actuarial loss (gain) $384.7
 $543.6
 $(7.6) $32.7
Prior service costs (credits) 8.3
 11.4
 (1.7) (3.5)
Total - Regulatory Assets (Liabilities) $393.0
 $555.0
 $(9.3) $29.2

We estimate that 2014 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs (credits) referred to above of $28.4 million and $(1.5) million, respectively.

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

  Pension OPEB
  2013 2012 2011 2013 2012 2011
  (Millions of Dollars)
Net Periodic Benefit Cost            
Service cost $13.9
 $19.8
 $14.5
 $9.5
 $9.8
 $9.9
Interest cost 52.4
 56.8
 58.4
 12.7
 16.7
 17.0
Expected return on plan assets (77.2) (71.8) (63.8) (14.5) (13.0) (11.2)
Amortization of:            
Transition obligation —
 —
 —
 —
 0.3
 0.3
Prior service cost (credit) 2.2
 2.1
 2.1
 (1.9) (1.9) (1.9)
Actuarial loss 41.7
 30.6
 24.3
 1.5
 5.0
 4.2
Settlement charge 1.5
 —
 —
 —
 —
 —
Other —
 0.4
 —
 —
 —
 —
Net Periodic Benefit Cost $34.5
 $37.9
 $35.5
 $7.3
 $16.9
 $18.3

  Pension OPEB
  2013 2012 2011 2013 2012 2011
Weighted-Average assumptions used to            
determine benefit obligations as of Dec. 31            
Discount rate 5.00% 4.10% 5.05% 4.95% 4.15% 5.20%
Rate of compensation increase 4.00% 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 4.10% 5.05% 5.60% 4.15% 5.20% 5.70%
Expected return on plan assets 7.25% 7.25% 7.25% 7.50% 7.50% 7.50%
Rate of compensation increase 4.00% 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% 8.0%/12.0%
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) 2021/2021 2017/2017 2017/2017

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2013, 2012 and 2011. 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.

91Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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

  1% Increase 1% Decrease
  (Millions of Dollars)
Effect on    
Post-retirement benefit obligation $25.5
 $(21.5)
Total of service and interest cost components $3.2
 $(2.6)

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

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

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

Our current pension plan target asset allocation is 45% equity investments and 55% fixed income investments. The current OPEB target asset allocation is 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and U.S. Treasuries.


92Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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

  As of December 31, 2013
Asset Category - Pension Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $16.9
 $—
 $—
 $16.9
Equities:        
U.S. Equity 418.5
 —
 —
 418.5
International Equity 117.8
 28.8
 —
 146.6
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 87.3
 407.0
 —
 494.3
International Bonds 62.9
 29.7
 —
 92.6
Total $703.4
 $465.5
 $—
 $1,168.9
  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

(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, 2013
Asset Category - OPEB Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $1.8
 $—
 $—
 $1.8
Equities:        
U.S. Equity 100.5
 —
 —
 100.5
International Equity 31.8
 1.9
 —
 33.7
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 5.7
 65.4
 —
 71.1
International Bonds 11.4
 3.9
 —
 15.3
Total $151.2
 $71.2
 $—
 $222.4


93Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

  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

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

Cash Flows:

Historical employer contributions:
  Pension  
Year Qualified Non-Qualified OPEB
  (Millions of Dollars)
       
2011 $234.1
 $5.2
 $45.6
2012 $88.5
 $6.0
 $13.6
2013 $—
 $7.5
 $10.1

Estimated benefit payments:
     
     
Year Pension Gross OPEB
  (Millions of Dollars)
     
2014 $91.6
 $13.6
2015 $86.0
 $14.5
2016 $87.9
 $15.5
2017 $88.3
 $16.5
2018 $87.0
 $17.6
2019-2023 $430.3
 $96.6

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, $12.5 million and $12.9 million during 2013, 2012 and 2011, respectively.

Postemployment Benefits:Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $2.8 million and $2.4 million as of December 31, 2013 and 2012, respectively.


O -- SEGMENT REPORTING

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

94Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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.

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

  Reportable Segments    
Year Ended Electric Gas Steam Other (a) Total
  (Millions of Dollars)
December 31, 2013          
Operating Revenues (b) $3,308.7
 $451.9
 $39.6
 $—
 $3,800.2
Depreciation and Amortization $249.5
 $25.5
 $3.6
 $—
 $278.6
Operating Income (c) $533.2
 $69.8
 $2.9
 $—
 $605.9
Equity in Earnings          
of Transmission Affiliate $60.2
 $—
 $—
 $—
 $60.2
Capital Expenditures $438.5
 $57.8
 $10.6
 $—
 $506.9
Total Assets (d) $11,393.0
 $685.0
 $74.3
 $133.3
 $12,285.6
           
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

(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.


P -- RELATED PARTIES

We provide to and receive from certain of our Wisconsin Energy affiliates managerial, financial, accounting, legal, data processing and other services in accordance with service agreements approved by the PSCW. In addition, we make lease payments to We Power for PWGS 1, PWGS 2, OC 1 and OC 2. We also receive and/or provide certain services to other associated companies in which we have, or Wisconsin Energy has, an equity investment.

95Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

American Transmission Company LLC:   As of December 31, 2013, we have a 23.0% interest in ATC. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which is reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while projects are under construction, including the generating units constructed as part of Wisconsin Energy's PTF strategy. ATC reimburses us for these costs when new generation is placed in service.

During the years ended December 31, 2013, 2012 and 2011, our equity in earnings and distributions received from ATC were as follows:

Equity Investee 2013 2012 2011
  (Millions of Dollars)
Equity in Earnings $60.2
 $57.6
 $54.9
       
Distributions Received $47.8
 $46.1
 $43.7

Summary financial information as of December 31 from the financial statements of ATC is as follows:

  2013 2012 2011
  (Millions of Dollars)
       
Operating Revenues $626.3
 $603.3
 $567.2
Operating Income $331.3
 $322.2
 $305.6
Net Income $247.6
 $237.4
 $223.9
       
Current Assets $80.7
 $63.1
 $58.7
Non-Current Assets $3,509.5
 $3,274.7
 $3,053.7
Current Liabilities $381.5
 $251.5
 $298.5
Non-Current Liabilities $1,676.2
 $1,645.8
 $1,482.7

We provided and received services from the following associated companies during 2013, 2012 and 2011:

Company 2013 2012 2011
  (Millions of Dollars)
Affiliate      
       
Services Provided      
We Power (excluding lease payments) $2.8
 $2.3
 $5.6
Wisconsin Gas $83.4
 $78.7
 $85.3
Wisconsin Energy $5.6
 $5.6
 $6.5
Other $1.6
 $1.2
 $1.1
       
Services Received      
We Power (including lease payments) $381.7
 $375.3
 $370.8
Wisconsin Gas $23.6
 $16.6
 $17.9
Wisconsin Energy $10.2
 $23.9
 $30.2
       
Equity Investee - ATC      
       
Services Provided $9.0
 $8.2
 $10.8
       
Services Received $234.2
 $222.7
 $219.2

96Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 Form 10-K

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

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


Q -- COMMITMENTS AND CONTINGENCIES

Operating Leases:   We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2018. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases, including leases for coal cars.

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

 (Millions of Dollars)
  
2014$3.9
20153.9
20163.7
20173.1
20183.2
Thereafter22.7
Total$40.5

Divested Assets:   Pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to WPL in connection with the sale of our interest in Edgewater Generating Unit 5.

Environmental Matters:   We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal combustion product disposal sites. We perform ongoing assessments of 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 $9 million to $17 millionover the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2013 and 2012, we established reserves of $10.8 million and $7.2 million, respectively, related to future remediation costs.


97Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2013 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 2013, 2012 and 2011, we incurred $0.1 million,$0.3 million and $0.2 million, respectively, in landfill remediation expenses. As of December 31, 2013, we have no reserves established related to coal combustion product landfill sites.

Valley Power Plant Title V Air Permit:   The WDNR renewed VAPP's Title V operating permit in February 2011. The term of the permit is five years. Sierra Club and Clean Wisconsin requested and were granted an administrative hearing before the WDNR on certain conditions of the permit; however, the case has been stayed. In addition, in March 2011, the Sierra Club petitioned the EPA for additional reductions and monitoring for particulate matter and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of either proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

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


R -- SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2013, we paid $120.5 million in interest, net of amounts capitalized, and received $39.2 million in net refunds from income taxes. During the year ended December 31, 2012, we paid $109.0 million in interest, net of amounts capitalized, and received $91.2 million in net refunds from income taxes. 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.

As of December 31, 2013, 2012 and 2011, the amount of accounts payable related to capital expenditures was $4.6 million, $15.7 million and $16.7 million, respectively.

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


S -- SUBSEQUENT EVENTS

On January 16, 2014, our Board of Directors declared a special dividend of $50.0 million which was paid to Wisconsin Energy on January 30, 2014.



98Wisconsin Electric Power Company
2013 Form 10-K

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Electric Power Company:

Milwaukee, Wisconsin

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary (the "Company"“Company”) as of December 31, 20132016 and 2012,2015, and the related consolidated income statements, statements of common equity, and statements of cash flows for each of the three years in the period ended December 31, 2013.2016. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company'sCompany’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'sCompany’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, 20132016 and 2012,2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013,2016, 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, 2014
28, 2017



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B. CONSOLIDATED INCOME STATEMENTS

Year Ended December 31      
(in millions) 2016 2015 2014
Operating revenues $3,792.8
 $3,854.1
 $4,059.4
       
Operating expenses      
Cost of sales 1,292.1
 1,399.0
 1,660.7
Other operation and maintenance 1,430.2
 1,384.9
 1,356.4
Depreciation and amortization 325.4
 304.0
 278.3
Property and revenue taxes 115.6
 117.3
 113.6
Total operating expenses 3,163.3
 3,205.2
 3,409.0
       
Operating income 629.5
 648.9
 650.4
       
Equity in earnings of transmission affiliate 55.5
 47.8
 57.9
Other income, net 9.1
 11.2
 8.7
Interest expense 117.6
 119.0
 116.5
Other expense (53.0) (60.0) (49.9)
       
Income before income taxes 576.5
 588.9
 600.5
Income tax expense 211.0
 212.0
 222.6
Net income 365.5
 376.9
 377.9
       
Preferred stock dividend requirements 1.2
 1.2
 1.2
Net income attributed to common shareholder $364.3
 $375.7
 $376.7

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


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C. CONSOLIDATED BALANCE SHEETS

At December 31    
(in millions, except share and per share amounts) 2016 2015
Assets    
Current assets    
Cash and cash equivalents $15.4
 $27.1
Accounts receivable and unbilled revenues, net of reserves of $40.9 and $43.0, respectively 503.2
 461.4
Accounts receivable from related parties 58.2
 41.1
Materials, supplies, and inventories 271.0
 301.6
Prepayments 138.0
 171.8
Other 24.6
 19.6
Current assets 1,010.4
 1,022.6
     
Long-term assets    
Property, plant, and equipment, net of accumulated depreciation of $3,619.6 and $3,461.9, respectively 9,832.3
 9,767.5
Regulatory assets 2,036.6
 1,855.9
Equity investment in transmission affiliate 402.0
 382.2
Other 90.2
 111.4
Long-term assets 12,361.1
 12,117.0
Total assets $13,371.5
 $13,139.6
     
Liabilities and Equity    
Current liabilities    
Short-term debt $159.0
 $144.0
Current portion of capital lease obligations 28.5
 123.6
Subsidiary note payable to WEC Energy Group 18.5
 19.6
Accounts payable 297.9
 286.4
Accounts payable to related parties 112.9
 95.7
Accrued payroll and benefits 51.8
 87.5
Accrued taxes 46.0
 15.6
Other 100.1
 100.1
Current liabilities 814.7
 872.5
     
Long-term liabilities    
Long-term debt 2,661.1
 2,658.8
Capital lease obligations 2,756.5
 2,692.5
Deferred income taxes 2,333.3
 2,110.0
Regulatory liabilities 853.9
 741.2
Pension and OPEB obligations 167.6
 210.9
Other 260.2
 259.3
Long-term liabilities 9,032.6
 8,672.7
     
Commitments and contingencies (Note 16) 
 
     
Common shareholder's equity    
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding 332.9
 332.9
Additional paid in capital 1,020.1
 999.7
Retained earnings 2,140.8
 2,231.4
Common shareholder's equity 3,493.8
 3,564.0
     
Preferred stock 30.4
 30.4
Total liabilities and equity $13,371.5
 $13,139.6

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

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D. CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31      
(in millions) 2016 2015 2014
Operating activities      
Net income $365.5
 $376.9
 $377.9
Reconciliation to cash provided by operating activities      
Depreciation and amortization 325.4
 323.7
 302.6
Deferred income taxes and investment tax credits, net 206.2
 178.9
 191.4
Contributions and payments related to pension and OPEB plans (8.0) (107.6) (10.4)
Equity income in transmission affiliate, net of distributions (17.2) (4.9) (7.4)
Payments for liabilities transferred to WBS (116.0) —
 —
Change in –      
Accounts receivable and unbilled revenues (59.0) (2.9) 91.0
Materials, supplies, and inventories 30.6
 18.8
 (39.5)
Prepaid taxes 39.4
 (2.8) (2.5)
Other current assets 9.3
 0.3
 (6.2)
Accounts payable 31.3
 (5.9) 18.2
Accrued taxes 30.4
 (42.1) (7.5)
Other current liabilities 10.7
 (1.2) (36.8)
Other, net (0.2) (56.8) (8.0)
Net cash provided by operating activities 848.4
 674.4
 862.8
       
Investing activities      
Capital expenditures (469.5) (519.2) (561.8)
Capital contributions to transmission affiliate (16.1) (4.6) (11.5)
Proceeds from the sale of assets 31.7
 0.2
 6.0
Proceeds from assets transferred to WBS 13.1
 —
 —
Other, net 4.0
 3.4
 (0.2)
Net cash used in investing activities (436.8) (520.2) (567.5)
       
Financing activities      
Dividends paid on common stock (455.0) (240.0) (390.0)
Dividends paid on preferred stock (1.2) (1.2) (1.2)
Issuance of long-term debt —
 500.0
 250.0
Retirement of long-term debt —
 (250.0) (300.0)
Change in short-term debt 15.0
 (162.8) 131.9
Repayment of subsidiary note to WEC Energy Group (1.1) (2.9) —
Other, net 19.0
 5.8
 12.9
Net cash used in financing activities (423.3) (151.1) (296.4)
       
Net change in cash and cash equivalents (11.7) 3.1
 (1.1)
Cash and cash equivalents at beginning of year 27.1
 24.0
 25.1
Cash and cash equivalents at end of year $15.4
 $27.1
 $24.0

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


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E. CONSOLIDATED STATEMENTS OF EQUITY

  Wisconsin Electric Power Company Common Shareholder's Equity    
  Common Stock Additional Paid-In Capital Retained Earnings Total Common Shareholder's Equity Preferred Stock Total Equity
(in millions)      
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
Net income —
 —
 365.5
 365.5
 —
 365.5
Dividends            
Common stock —
 —
 (455.0) (455.0) —
 (455.0)
Preferred stock —
 —
 (1.2) (1.2) —
 (1.2)
Stock-based compensation —
 1.1
 —
 1.1
 —
 1.1
Tax benefit of exercised stock options allocated from parent —
 19.3
 —
 19.3
 —
 19.3
Other —
 —
 0.1
 0.1
 —
 0.1
Balance at December 31, 2016 $332.9
 $1,020.1
 $2,140.8
 $3,493.8
 $30.4
 $3,524.2

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


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F. CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31
(in millions)
     2016 2015
Common shareholder's equity (see accompanying statement) 3,493.8
 3,564.0
Preferred stock 30.4
 30.4
Long-term debt Interest Rate Year Due    
Debentures (unsecured) 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
 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
 250.0
  6.875% 2095 100.0
 100.0
         
Note (secured, nonrecourse) 4.81% 2030 2.0
 2.0
         
Obligations under capital leases     2,785.0
 2,816.1
Total     5,472.0
 5,503.1
Unamortized debt issuance costs     (3.6) (3.9)
Unamortized discount, net     (22.3) (24.3)
Total long-term debt and capital lease obligations, including current portion     5,446.1
 5,474.9
Current portion of capital lease obligations     (28.5) (123.6)
Total long-term debt and capital lease obligations     5,417.6
 5,351.3
Total long-term capitalization     $8,941.8
 $8,945.7

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


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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, Acquisitions, for more information on this acquisition.

We are an electric, natural gas, and steam utility company that serves electric customers in Wisconsin and an iron ore mine owned by the Tilden Mining Company (Tilden) in the Upper Peninsula of Michigan, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin.

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and it became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets previously held by us and WPS located in the Upper Peninsula of Michigan. The existing contract between us and the Tilden Mining Company will remain in place until a new power generation solution for the region is commercially operational.

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, 2016, we had one wholly owned subsidiary, Bostco. Bostco had total assets of $24.4 million and $29.8 million as of December 31, 2016 and 2015, 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.

During the second quarter of 2016, we reorganized our business segments to reflect our new internal organization and management structure. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 21, Segment Information, for more information on our business segments.

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) Balance Sheet Presentation— To be consistent with the current year presentation, we changed our December 31, 2015 balance sheet from a utility format to a traditional format. This change revised the order of certain balance sheet line items, but it did not result in any change to the classification of amounts between line items.

(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.

(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 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 ROE than authorized by the PSCW.


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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 20, Regulatory Environment, 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 revenues. 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 provided electric service to customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 4, Related Parties, and Note 20, Regulatory Environment, for information regarding the transfer of our customers located in the Upper Peninsula of Michigan to UMERC as of January 1, 2017. 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, 2016. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2016.

(e) Materials, Supplies, and Inventories—Our inventory as of December 31 consisted of:
(in millions) 2016 2015
Materials and supplies $148.1
 $151.1
Fossil fuel 91.1
 110.5
Natural gas in storage 31.8
 40.0
Total $271.0
 $301.6

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 revenues 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 7, 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 both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation over the estimated useful life of utility property using depreciation rates approved by the PSCW and MPSC that include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.00%, 3.01%, and 2.93% in 2016, 2015, and 2014, respectively.

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We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

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 2016 and 2015, and 9.09% for 2014. Our average AFUDC wholesale rates were 2.73%, 1.72%, and 0.87% for 2016, 2015, and 2014, respectively.

We recorded the following AFUDC for the years ended December 31:
(in millions) 2016 2015 2014
AFUDC – Debt $1.7
 $2.2
 $1.8
AFUDC – Equity $4.2
 $5.7
 $4.4

(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. An ARO 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 ARO liabilities are accreted to their present values each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are 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 9, 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 9, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 16, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

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

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assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We 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 14, 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 15, Employee Benefits, for more information.

(m) Stock-Based Compensation—Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides a long-term incentive through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million.

Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period based on an estimate of the final expected value of the awards.

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.

WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models:
  2016
2015
2014
Non-qualified stock options granted * 92,880
 495,550
 864,860
       
Estimated fair value per non-qualified stock option $4.92
 $5.29
 $4.18
       
Risk-free interest rate 0.5% – 2.2%
 0.1% – 2.1%
 0.1% – 3.0%
Dividend yield 4.0% 3.7% 3.8%
Expected volatility 18.0% 18.0% 18.0%
Expected life (years) 5.8
 5.8
 5.8

*
Effective January 1, 2016, certain of our employees were transferred into WBS.See Note 4, Related Parties, for more information.
The risk-free interest rate is based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's current dividend rate and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience.


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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. The restricted shares are classified as equity awards.

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 shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three-year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. All grants are settled in cash and are accounted for as liability awards accordingly. Stock-based compensation costs are recorded over the three-year performance period.

See Note 10, Common Equity, for more information on WEC Energy Group's stock-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 at their value as of the end of the reporting period.

Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, 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 on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

See Note 17, Fair Value Measurements, for more information.


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(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. Our regulated hedging programs are approved by the PSCW.

We record derivative instruments on our balance sheets as assets or liabilities 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. Realized 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, and cash collateral received is reflected in other current liabilities. See Note 18, 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—ACQUISITIONS

Parent Company's Acquisition of Integrys

On June 29, 2015, our parent company acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc. Integrys is a provider of regulated natural gas and electricity, as well as nonregulated renewable energy.

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 are 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. For the year ended December 31, 2016, we recorded $21.1 million of expense related to this earnings sharing mechanism.

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 WPS 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.

In 2015, we recorded $6.6 million of severance expense that resulted from employee reductions related to the post-acquisition integration. Severance expense incurred during 2016 was not significant. The severance expense was recorded in our utility segment and is included in the other operation and maintenance line item on the income statements. Severance payments of $4.6 million and

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$1.2 million were made during 2016 and 2015, respectively. The severance accruals on our balance sheets were not significant at December 31, 2016 and 2015.

Parent Company's Acquisition of a Natural Gas Storage Facility in Michigan

In January 2017, our parent company signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide for some of our storage needs for our natural gas utility operations. We plan to enter into a long-term service agreement to take the allocated storage, subject to PSCW approval and closing of the acquisition. PSCW approval and closing of this transaction are expected to occur by the third quarter of 2017.

NOTE 3—DISPOSITIONS

Utility Segment – Sale of Milwaukee County Power Plant

In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ($6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

NOTE 4—RELATED PARTIES

We and our consolidated subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, ATC, and other affiliated entities.

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 AIA (Non-WBS AIA) went into effect. The Non-WBS AIA governed the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS continued to provide services to Integrys and its subsidiaries only under the existing WBS AIAs. WBS provided services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us, under interim WBS AIAs. The PSCW and all other relevant state commissions approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA.

Services under the Non-WBSAIA were subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary were priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary were priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary were priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS were priced at cost.

WBSprovided several categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBSAIAs, which were approved, or from which we were 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.

On April 1, 2016, we, along with WEC Energy Group, filed a new agreement for approval with the PSCW and all other relevant state commissions. The PSCW approved the new agreement in August 2016. We later received approval from the two other states reviewing the agreement, and the new agreement took effect January 1, 2017. The new agreement replaces the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements being replaced. In February 2017, a request was filed with the PSCW for modifications to the new AIA to incorporate WEC Energy Group's acquisition of a natural gas storage facility in Michigan. See Note 2, Acquisitions, for more information on the natural gas storage facility acquisition.


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Effective January 1, 2016, 485 of our employees were transferred into WBS. In connection with this transfer of employees, certain benefit-related liabilities were also transferred to WBS. In addition, we transferred certain software assets to WBS in 2016.

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. On January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information.

Bostco has a note payable to our parent company, WEC Energy Group. At December 31, 2016 and 2015, the balance of this note payable was $18.5 million and $19.6 million, respectively.

The following table shows activity associated with our related party transactions for the years ended December 31:
(in millions) 2016 2015 2014
Lease agreements  
  
  
Lease payments to We Power (1)
 $412.2
 $410.5
 $389.0
CWIP billed to We Power 37.9
 58.8
 41.0
       
Transactions with WBS (2)
      
Billings to WBS (3)
 213.8
 11.1
 —
Billings from WBS (4)
 310.6
 1.3
 —
       
Transactions with WPS (2)
    
  
Billings to WPS 9.0
 13.4
 —
Billings from WPS 4.2
 4.9
 —
       
Transactions with WG    
  
Natural gas purchases from WG 5.3
 5.3
 6.6
Services received from WG 21.5
 23.5
 20.6
Services provided to WG 60.6
 79.4
 81.7

(1)
We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS 1, PWGS 2, ER 1, and ER 2.

(2)
Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs discussed above.

(3)
Includes $13.1 million for the transfer of certain software assets to WBS for the year ended December 31, 2016.

(4)
Includes $116.0 million for the transfer of certain benefit-related liabilities to WBS for the year ended December 31, 2016.

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The estimated net book value of the property, plant, and equipment transferred to UMERC from us as of January 1, 2017, was $83 million. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in a gain or loss recognized.

UMERC obtains its energy through the MISO Energy Markets and meets its market obligations through power purchase agreements with us and WPS. The new utility has also proposed a long-term generation solution for electric reliability in the region. See Note 20, Regulatory Environment, for more information. The Tilden Mining Company will remain a customer of ours until this new generation begins commercial operation.


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NOTE 5—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

At December 31, 2016, we owned approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. On January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in a gain or loss recognized. WEC Energy Group has 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) 2016 2015 2014
Balance at beginning of period $382.2
 $372.9
 $354.1
Add: Earnings from equity method investment 55.5
 47.8
 57.9
Add: Capital contributions 16.1
 4.6
 11.5
Less: Distributions 51.7
*42.9
 50.5
Less: Other 0.1
 0.2
 0.1
Balance at end of period $402.0
 $382.2
 $372.9

*Of this amount, $13.4 million was recorded as a receivable at December 31, 2016.

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 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) 2016 2015 2014
Charges to ATC for services and construction $10.0
 $9.7
 $8.1
Charges from ATC for network transmission services 247.8
 238.5
 231.4

As of December 31, 2016 and 2015, our balance sheets included the following receivables and payables related to ATC:
(in millions) 2016 2015
Accounts receivable    
Services provided to ATC $1.1
 $0.6
Accounts payable    
Services received from ATC 20.0
 19.9

Summarized financial data for ATC is included in the tables below:
(in millions) 2016 2015 2014
Income statement data      
Revenues $650.8
 $615.8
 $635.0
Operating expenses 322.5
 319.3
 307.4
Other expense 95.5
 96.1
 88.9
Net income $232.8
 $200.4
 $238.7


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(in millions) December 31, 2016 December 31, 2015
Balance sheet data    
Current assets $75.8
 $80.5
Noncurrent assets 4,312.9
 3,948.3
Total assets $4,388.7
 $4,028.8
     
Current liabilities $495.1
 $330.3
Long-term debt 1,865.3
 1,790.7
Other noncurrent liabilities 271.5
 245.0
Shareholders' equity 1,756.8
 1,662.8
Total liabilities and shareholders' equity $4,388.7
 $4,028.8

NOTE 6—SUPPLEMENTAL CASH FLOW INFORMATION
(in millions) 2016 2015 2014
Cash (paid) for interest, net of amount capitalized $(116.2) $(116.2) $(117.9)
Cash received (paid) for income taxes, net 100.2
 (58.5) (20.8)
Significant non-cash transactions:      
Accounts payable related to construction costs 9.1
 11.7
 1.7

NOTE 7—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets as of December 31:
(in millions) 2016 2015 See Note
Regulatory assets (1) (2)
      
Plant related – capital leases $724.8
 $674.4
 13
Unrecognized pension and OPEB costs (3)
 520.3
 535.8
 15
Electric transmission costs 231.9
 191.5
 20
Income tax related items (4)
 200.8
 177.4
  
SSR 188.1
 86.1
 20
We Power generation (5)
 54.1
 45.4
  
AROs 39.7
 36.3
 9
Energy efficiency programs (6)
 38.5
 50.7
  
Other, net 38.4
 58.3
  
Total regulatory assets $2,036.6
 $1,855.9
  

(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.

(2)
As of December 31, 2016, we had $10.4 million of regulatory assets not earning a return and $204.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures.
(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 remaining service life of each plan.

(4)
Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse.

(5)
Represents amounts recoverable from customers related to our costs of the generating units leased from We Power, including subsequent capital additions.

(6)
Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards.


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The following regulatory liabilities were reflected on our balance sheets as of December 31:
(in millions) 2016 2015
Regulatory liabilities    
Removal costs (1)
 $722.9
 $696.9
Mines deferral (2)
 70.2
 31.6
Other, net 71.0
 12.7
Total regulatory liabilities $864.1
 $741.2
     
Balance Sheet Presentation    
Other current liabilities $10.2
 $—
Regulatory liabilities 853.9
 741.2
Total regulatory liabilities $864.1
 $741.2

(1)
Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.

(2)
Represents the deferral of revenues less the associated cost of sales related 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 8—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31:
(in millions) 2016 2015
Utility property, plant, and equipment $11,232.9
 $10,863.1
Less: Accumulated depreciation 3,606.9
 3,447.2
Net 7,626.0
 7,415.9
CWIP 111.5
 170.3
Net utility property, plant, and equipment 7,737.5
 7,586.2
     
Property under capital leases 2,898.0
 2,876.7
Less: Accumulated amortization 837.8
 735.0
Net leased facilities 2,060.2
 2,141.7
     
Non-utility and other property, plant, and equipment 46.4
 54.0
Less: Accumulated depreciation 12.7
 14.7
Net 33.7
 39.3
CWIP 0.9
 0.3
Net non-utility and other property, plant, and equipment 34.6
 39.6
     
Total property, plant, and equipment $9,832.3
 $9,767.5

On January 1, 2017, we transferred 2,500 miles of electric distribution lines and related electric distribution substations in the Upper Peninsula of Michigan to UMERC. The estimated net book value of the property, plant, and equipment we transferred to UMERC was $83 million. See Note 4, Related Parties, for more information.

NOTE 9—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.


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The following table shows changes to our AROs during the years ended December 31:
(in millions) 2016 2015 2014
Balance as of January 1 $58.7
 $40.5
 $39.4
Accretion 3.0
 2.3
 2.2
Additions —
 15.9
*—
Liabilities settled (0.2) —
 (1.1)
Balance as of December 31 $61.5
 $58.7
 $40.5

*During 2015, an ARO was recorded for the fly-ash landfills located at our generation facilities.

NOTE 10—COMMON EQUITY

Stock-Based Compensation Plans

The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit for the years ended December 31:
(in millions) 2016 2015 2014
Stock options $1.8
 $3.2
 $3.6
Restricted stock 1.8
 2.1
 2.1
Performance units 3.9
 7.5
 12.7
Stock-based compensation expense $7.5
 $12.8
 $18.4
Related tax benefit $3.0
 $5.1
 $7.4

Stock-based compensation costs capitalized during 2016, 2015, and 2014 were not significant.

Stock Options

The following is a summary of our employees' WEC Energy Group stock option activity during 2016:
Stock Options Number of Options Weighted-Average Exercise Price 
Weighted-Average Remaining Contractual Life (in years)
 
Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2016 5,687,714
 $33.58
    
Granted 92,880
 $50.93
    
Exercised (439,043) $27.57
    
Transferred * (4,055,745) $34.68
    
Outstanding as of December 31, 2016 1,285,806
 $33.41
 4.6 $32.4
Exercisable as of December 31, 2016 1,010,061
 $29.64
 3.7 $29.3

*
Relates to the transfer of certain employees into WBS.See Note 4, Related Parties, for more information.

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2016. This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2016, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2016, 2015, and 2014 was $14.1 million, $34.6 million, and $47.5 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $12.1 million, $29.2 million, and $47.9 million during the years ended December 31, 2016, 2015, and 2014, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $5.6 million, $14.0 million, and $18.8 million, respectively.

As of December 31, 2016, our estimated unrecognized compensation cost related to unvested WEC Energy Group stock options was not significant.


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During the first quarter of 2017, the Compensation Committee awarded 80,770 non-qualified WEC Energy Group stock options with an exercise price of $58.31 and a weighted-average grant date fair value of $7.12 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following is a summary of our employees' WEC Energy Group restricted stock activity during 2016:
Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value
Outstanding as of January 1, 2016 175,443
 $47.66
Granted 8,049
 $51.78
Released (7,901) $44.66
Transferred * (158,635) $47.73
Forfeited (695) $50.42
Outstanding as of December 31, 2016 16,261
 $50.39

*
Relates to the transfer of certain employees into WBS.See Note 4, Related Parties, for more information.

The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.4 million, $2.7 million, and
$2.3 million for the years ended December 31, 2016, 2015, and 2014, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.2 million, $1.1 million, and $0.9 million, respectively.

As of December 31, 2016, our estimated unrecognized compensation cost related to WEC Energy Group restricted stock was not significant.

During the first quarter of 2017, the Compensation Committee awarded 8,001 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $58.10 per share.

Performance Units

In 2016, 2015, and 2014, the Compensation Committee awarded 35,700; 187,450; and 224,735 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan.

In 2016, we transferred 573,499 performance units to WBS in connection with the transfer of certain employees. See Note 4, Related Parties, for more information.

Performance units with an intrinsic value of $3.4 million, $11.6 million, and $13.1 million were settled during 2016, 2015, and 2014, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units for the same years was approximately $0.5 million, $4.2 million, and $4.7 million, respectively.

As of December 31, 2016, we expect to recognize approximately $4.4 million of unrecognized compensation cost related to WEC Energy Group performance units over the next 1.4 years on a weighted-average basis.

During the first quarter of 2017, performance units held by our employees with an intrinsic value of $1.4 million were settled. The actual tax benefit realized from the distribution of these awards was $0.4 million. In January 2017, the Compensation Committee also awarded 34,765 WEC Energy Group 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.


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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 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 12, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2016, our restricted retained earnings totaled $1.9 billion. Our equity in undistributed earnings of investees accounted for by the equity method was $142.2 million at December 31, 2016.

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

NOTE 11—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2016 and 2015:
(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       $30.4

NOTE 12—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:
(in millions, except percentages) 2016 2015
Commercial paper    
Amount outstanding at December 31 $159.0
 $144.0
Average interest rate on amounts outstanding at December 31 0.87% 0.70%

Our average amount of commercial paper borrowings based on daily outstanding balances during 2016 was $110.0 million, with a weighted-average interest rate during the period of 0.54%.

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, 2016, we had approximately $323.0 million of available capacity under our bank back-up credit facility and $159.0 million of commercial paper outstanding that was supported by the credit facility. As of December 31, 2016, our subsidiary had an $18.5 million note payable to WEC Energy Group with a weighted-average interest rate of 5.17%.


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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 2016
Revolving credit facility December 2020 $500.0
     
Less:    
Letters of credit issued inside credit facility   $18.0
Commercial paper outstanding   159.0
     
Available capacity under existing agreement   $323.0

This 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 13—LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

See our statements of capitalization for details on our long-term debt.

Debentures and Notes

The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2016:
(in millions)  
2017 $—
2018 250.0
2019 250.0
2020 —
2021 300.0
Thereafter 1,887.0
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 a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of
$80.0 million. In August 2009, we terminated a letter 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, 2016, the repurchased bonds were still outstanding, but are not reported in our long-term debt or included in our capitalization statements since they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on this bond series and have it remarketed to third parties. A related bond series that had an outstanding principal amount of $67.0 million matured on August 1, 2016.

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 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 leases with We Power 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

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accounting as a deferred regulatory asset on our balance sheets. See Note 7, Regulatory Assets and Liabilities, for more information on our plant related capital leases.

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 zero 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.

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as cost of sales on 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. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately
$78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $29.6 million as of December 31, 2016, and will decrease to zero over the remaining life of the contract.

Port Washington Generating Station

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 units and corresponding obligations for the units have been recorded at the estimated fair value of $704.2 million. We are amortizing the leased units 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 $130.8 million in the year 2021 for PWGS 1 and to approximately $131.6 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 units was $636.1 million as of December 31, 2016, and will decrease to zero over the remaining lives of the contracts.

Elm Road Generating Station

We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30-year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The leased units and corresponding capital lease obligations have been recorded at the estimated fair value of $2,053.5 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 $542.8 million in the year 2029 for ER 1 and to approximately $447.2 million in the year 2030 for ER 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 was $2,119.3 million as of December 31, 2016, and will decrease to zero over the remaining lives of the contracts.

We paid the following lease payments during 2016, 2015, and 2014:
(in millions) 2016 2015 2014
Long-term power purchase commitment $37.6
 $36.2
 $34.9
PWGS  82.4
 103.8
 99.2
ERGS 329.8
 306.7
 277.8
Total $449.8
 $446.7
 $411.9


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The following table summarizes our capitalized leased facilities as of December 31:
(in millions) 2016 2015
Long-term power purchase commitment    
Under capital lease $140.3
 $140.3
Accumulated amortization (109.5) (103.9)
Total long-term power purchase commitment $30.8
 $36.4
     
PWGS     
Under capital lease $704.2
 $692.5
Accumulated amortization (274.7) (245.7)
Total PWGS  $429.5
 $446.8
     
ERGS    
Under capital lease $2,053.5
 $2,043.9
Accumulated amortization (453.6) (385.4)
Total ERGS $1,599.9
 $1,658.5
     
Total leased facilities $2,060.2
 $2,141.7

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2016 are as follows:
(in millions) Power Purchase Commitment PWGS ERGS Total
2017 $13.9
 $102.7
 $315.4
 $432.0
2018 14.7
 102.7
 315.4
 432.8
2019 15.5
 102.7
 315.4
 433.6
2020 16.4
 102.7
 315.4
 434.5
2021 17.2
 102.7
 315.4
 435.3
Thereafter 7.6
 1,020.2
 5,828.7
 6,856.5
Total minimum lease payments 85.3
 1,533.7
 7,405.7
 9,024.7
Less: Estimated executory costs (39.9) —
 —
 (39.9)
Net minimum lease payments 45.4
 1,533.7
 7,405.7
 8,984.8
Less: Interest (15.8) (897.6) (5,286.4) (6,199.8)
Present value of minimum lease payments 29.6
 636.1
 2,119.3
 2,785.0
Less: Due currently (2.7) (13.9) (11.9) (28.5)
Long-term obligations under capital lease $26.9
 $622.2
 $2,107.4
 $2,756.5

NOTE 14—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) 2016 2015 2014
Current tax expense $4.8
 $33.1
 $31.2
Deferred income taxes, net 207.3
 180.0
 192.5
Investment tax credit, net (1.1) (1.1) (1.1)
Total income tax expense $211.0
 $212.0
 $222.6


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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 United States statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following:
  2016 2015 2014
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate
Expected tax at statutory federal tax rates $201.4
 35.0 % $205.7
 35.0 % $209.8
 35.0 %
State income taxes net of federal tax benefit 31.8
 5.5 % 31.0
 5.3 % 33.0
 5.5 %
Production tax credits (16.5) (2.8)% (17.8) (3.0)% (17.4) (2.9)%
Domestic production activities deduction (7.8) (1.4)% (7.8) (1.3)% —
 — %
AFUDC – Equity (1.5) (0.3)% (2.0) (0.3)% (1.5) (0.2)%
Investment tax credit restored (1.1) (0.2)% (1.1) (0.2)% (1.1) (0.2)%
Other, net 4.7
 0.8 % 4.0
 0.5 % (0.2) (0.1)%
Total income tax expense $211.0
 36.6 % $212.0
 36.0 % $222.6
 37.1 %

Deferred Income Tax Assets and Liabilities

The components of deferred income taxes as of December 31 were as follows:
(in millions) 2016 2015
Deferred tax assets    
Deferred revenues $207.2
 $219.9
Future federal tax benefits 143.7
 72.9
Employee benefits and compensation 77.6
 103.2
Construction advances 20.0
 17.7
Uncollectible account expense 16.1
 14.3
Emission allowances 0.2
 0.2
Other 70.9
 48.7
Total deferred tax assets 535.7
 476.9
     
Deferred tax liabilities    
Property-related 2,257.3
 2,058.5
Investment in transmission affiliate 195.1
 174.9
Employee benefits and compensation 179.3
 164.6
Deferred transmission costs 93.1
 76.7
Prepaid tax, insurance, and other 50.2
 50.6
Other 94.0
 61.6
Total deferred tax liabilities 2,869.0
 2,586.9
Deferred tax liability, net $2,333.3
 $2,110.0

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, 2016, we had $82.8 million and $107.2 million of federal net operating loss and tax credit carryforwards resulting in deferred tax assets of $29.0 million and $107.2 million, respectively. These federal net operating loss and tax credit carryforwards begin to expire in 2031. We expect to have future taxable income sufficient to utilize these deferred tax assets. As of December 31, 2015, we had approximately $72.9 million of deferred tax assets associated with tax credit carryforwards. As of December 31, 2016 we had $149.9 million state net operating loss carryforwards resulting in deferred tax assets of $7.5 million. These state net operating loss carryforwards begin to expire in 2025. We expect to have 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) 2016 2015
Balance as of January 1 $6.1
 $7.2
Reductions for tax positions of prior years (1.0) (1.1)
Balance as of December 31 $5.1
 $6.1

The amount of unrecognized tax benefits as of December 31, 2016 and 2015 excludes deferred tax assets related to uncertainty in income taxes of $5.1 million and $6.1 million, respectively. As of December 31, 2016 and 2015, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2016, 2015, and 2014, we recognized $0.2 million of interest expense, $0.1 million of interest income, and $0.3 million of interest expense, respectively, in our income statements. For the years ended December 31, 2016, 2015, and 2014, we recognized no penalties in our income statements. As of December 31, 2016 and 2015, we had $0.7 million and $0.6 million, respectively, of interest accrued on our balance sheets.

Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2013 through 2016 are subject to federal examination and the tax years 2012 through 2016 are subject to examination by the state of Wisconsin.

NOTE 15—EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We participate in WEC Energy Group's defined benefit pension plans and OPEB plans that cover substantially all of our employees. We are responsible for our share of the plan assets and obligations. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. 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. New management employees hired after December 31, 2014 receive a 6% annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit 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) 2016 2015 2016 2015
Change in benefit obligation        
Obligation at January 1 $1,290.6
 $1,315.2
 $313.8
 $322.3
Service cost 10.5
 14.7
 7.3
 9.0
Interest cost 49.7
 52.9
 13.2
 13.4
Participant contributions —
 —
 8.8
 8.8
Plan amendments (2.6) —
 —
 —
Transfer to affiliates * (121.1) (2.4) (17.0) —
Actuarial loss (gain) 25.3
 (11.5) (9.7) (22.3)
Benefit payments (75.4) (78.3) (19.0) (18.7)
Federal subsidy on benefits paid N/A
 N/A
 1.1
 1.3
Obligation at December 31 $1,177.0
 $1,290.6
 $298.5
 $313.8
         
Change in fair value of plan assets        
Fair value at January 1 $1,179.3
 $1,160.0
 $216.1
 $224.9
Actual return on plan assets 73.0
 (7.8) 13.5
 (1.5)
Employer contributions 5.3
 105.0
 2.7
 2.6
Participant contributions —
 —
 8.8
 8.8
Transfer to/from affiliates * (79.4) 0.4
 (17.0) —
Benefit payments (75.4) (78.3) (19.0) (18.7)
Fair value at December 31 $1,102.8
 $1,179.3
 $205.1
 $216.1
Funded status at December 31 $(74.2) $(111.3) $(93.4) $(97.7)

*Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. See Note 4, Related Parties, for more information.

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) 2016 2015 2016 2015
Other long-term assets $—
 $—
 $—
 $1.9
Pension and OPEB obligations 74.2
 111.3
 93.4
 99.6
Total net liabilities $(74.2) $(111.3) $(93.4) $(97.7)

The accumulated benefit obligation for all defined benefit pension plans was $1,175.8 million and $1,287.5 million as of December 31, 2016 and 2015, respectively.

The following table shows information for the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:
(in millions) 2016 2015
Projected benefit obligation $1,177.0
 $1,290.2
Accumulated benefit obligation 1,175.8
 1,289.5
Fair value of plan assets 1,102.8
 1,178.9

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) 2016 2015 2016 2015
Net regulatory assets        
Net actuarial loss $518.5
 $520.9
 $4.6
 $14.7
Prior service cost (credit) 0.2
 4.3
 (3.0) (4.1)
Total $518.7
 $525.2
 $1.6
 $10.6


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The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2017:
(in millions) Pension Costs OPEB Costs
Net actuarial loss $35.4
 $1.0
Prior service costs (credits) 1.1
 (1.1)
Total 2017 – estimated amortization
 $36.5
 $(0.1)

The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows:
  Pension Costs OPEB Costs
(in millions) 2016 2015 2014 2016 2015 2014
Service cost $10.5
 $14.7
 $9.4
 $7.3
 $9.0
 $8.1
Interest cost 49.7
 52.9
 59.3
 13.2
 13.4
 14.4
Expected return on plan assets (77.7) (83.6) (79.1) (14.0) (16.0) (16.2)
Amortization of prior service cost (credit) 1.6
 2.0
 2.0
 (1.1) (1.1) (1.7)
Amortization of net actuarial loss 32.4
 35.6
 26.9
 1.0
 1.0
 0.2
Net periodic benefit cost $16.5
 $21.6
 $18.5
 $6.4
 $6.3
 $4.8

The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:
  Pension OPEB
  2016 2015 2016 2015
Discount rate 4.15% 4.45% 4.20% 4.45%
Rate of compensation increase 3.20% 4.00% N/A N/A
Assumed medical cost trend rate N/A N/A 7.00% 7.50%
Ultimate trend rate N/A N/A 5.00% 5.00%
Year ultimate trend rate is reached N/A N/A 2021 2021

The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:
  Pension Costs
  2016 2015 2014
Discount rate 4.45% 4.15% 5.00%
Expected return on plan assets 7.00% 7.00% 7.25%
Rate of compensation increase 3.50% 4.00% 4.00%

  OPEB Costs
  2016 2015 2014
Discount rate 4.45% 4.20% 4.95%
Expected return on plan assets 7.25% 7.25% 7.50%
Assumed medical cost trend rate (Pre 65/Post 65) 7.50% 7.50% 7.50%
Ultimate trend rate 5.00% 5.00% 5.00%
Year ultimate trend rate is reached 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 2017, the expected return on assets assumption is 7.00% for the pension plan and 7.25% for the OPEB plan.


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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, 2016, 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 $2.9
 $(2.3)
Effect on the health care component of the accumulated postretirement benefit obligation 31.5
 (26.0)

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 pension trust target asset allocation is 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The 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 United States 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. Following our adoption of ASU 2015-07 on January 1, 2016, the assets that are not subject to leveling are investments that are valued using the net asset value per share (or its equivalent) practical expedient. We have applied this approach retrospectively to the 2015 table for comparability.

The following table summarizes the fair values of our investments by asset class:
  December 31, 2016
  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 $1.1
 $19.2
 $—
 $20.3
 $6.5
 $1.3
 $—
 $7.8
Equity securities:                
Unites States Equity 85.5
 0.1
 —
 85.6
 10.5
 —
 —
 10.5
International Equity 17.7
 —
 —
 17.7
 1.3
 —
 —
 1.3
Fixed income securities: *                
United States Bonds —
 455.3
 —
 455.3
 —
 44.0
 —
 44.0
International Bonds —
 31.6
 —
 31.6
 —
 2.8
 —
 2.8
Private Equity and Real Estate —
 —
 11.0
 11.0
 —
 —
 0.7
 0.7
  $104.3
 $506.2
 $11.0
 $621.5
 $18.3
 $48.1
 $0.7
 $67.1
Investments measured at net asset value       $481.3
       $138.0
Total $104.3
 $506.2
 $11.0
 $1,102.8
 $18.3
 $48.1
 $0.7
 $205.1

*This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

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  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:                
United States equity 80.1
 —
 —
 80.1
 11.8
 —
 —
 11.8
International equity 25.8
 —
 —
 25.8
 1.7
 —
 —
 1.7
Fixed income securities: *                
United States bonds —
 509.4
 —
 509.4
 —
 78.1
 —
 78.1
International bonds —
 32.6
 —
 32.6
 —
 4.5
 —
 4.5
Private Equity and Real Estate —
 —
 4.5
 4.5
 —
 —
 0.3
 0.3
  $121.4
 $542.0
 $4.5
 $667.9
 $15.9
 $82.6
 $0.3
 $98.8
Investments measured at net asset value       $511.4
       $117.3
Total $121.4
 $542.0
 $4.5
 $1,179.3
 $15.9
 $82.6
 $0.3
 $216.1

*This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

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, 2016 $4.5
 $0.3
Purchases 6.5
 0.4
Ending balance at December 31, 2016 $11.0
 $0.7

  Private Equity and Real Estate
(in millions) Pension OPEB
Beginning balance at January 1, 2015 $—
 $—
Purchases 4.5
 0.3
Ending balance at December 31, 2015 $4.5
 $0.3

Cash Flows

We expect to contribute $4.9 million to the pension plans in 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. We do not expect to contribute to the OPEB plans in 2017.

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
2017 $90.7
 $13.3
2018 88.6
 14.4
2019 86.6
 15.3
2020 86.5
 16.1
2021 82.7
 16.8
2022-2026 381.1
 89.3

Savings Plans

We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. Total costs incurred under these plans were $10.4 million in 2016, and $13.0 million in both 2015 and 2014.

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NOTE 16—COMMITMENTS AND CONTINGENCIES

We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, operating leases, environmental matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

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.

The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2016.
      Payments Due By Period
(in millions) Date Contracts Extend Through Total Amounts Committed 2017 2018 2019 2020 2021 Later Years
Electric utility:                
Nuclear 2033 $9,599.8
 $415.3
 $420.1
 $445.4
 $475.1
 $501.1
 $7,342.8
Coal supply and transportation 2019 313.1
 183.6
 97.5
 32.0
 —
 —
 —
Purchased power 2031 86.0
 30.5
 21.7
 9.2
 6.9
 5.9
 11.8
Natural gas utility supply and transportation 2024 217.2
 56.3
 49.3
 43.0
 31.5
 17.9
 19.2
Total   $10,216.1
 $685.7
 $588.6
 $529.6
 $513.5
 $524.9
 $7,373.8

Operating Leases

We lease property, plant, and equipment under various terms. 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 $5.0 million, $6.7 million, and $4.8 million in 2016, 2015, and 2014, respectively.

Future minimum payments under noncancelable operating leases are payable as follows:

Year Ending December 31
 
Payments
(in millions)
2017 $4.4
2018 3.3
2019 1.4
2020 1.3
2021 1.4
Later years 21.7
Total $33.5

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;

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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 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-fired power 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.

Air Quality

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, 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 emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets discussed below apply to 2017 and beyond.

In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and issued the final rule in September 2016. Starting in 2017, this rule requires reductions in the ozone season (May 1 through September 30) NOxemissions from power plants in 23 states in the eastern United States, including Wisconsin. The EPA updated Phase II CSAPR NOxozone season budgets for electric generating units in the affected states. In the final rule, the EPA significantly increased the NOx ozone season budget from the proposed rule for Wisconsin starting in 2017. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.

Sulfur Dioxide National Ambient Air 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 some latitude in rule implementation. 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 required the EPA to complete attainment designations for certain areas with large sources by no later than July 2016. SO2 emissions from PIPP are above the consent decree emission threshold, which means that the Marquette area required action earlier than would otherwise have been required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. In July 2016, the EPA finalized its recommendation and published a notice in the Federal Register designating Marquette County, Michigan as unclassified/attainment, effective September 2016.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

8-Hour Ozone National Ambient Air 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 of Wisconsin 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. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.

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Mercury and Other Hazardous Air Pollutants

In December 2011, the EPA issued the final MATS rule, which imposed 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 Supreme Court ruled on a challenge to the MATS rule and remanded the case back to the D.C. Circuit Court of Appeals, ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule remains in effect until the D.C. Circuit Court of Appeals takes action on the EPA's April 2016 updated cost evaluation.

We believe that our fleet is well positioned to comply with the final MATS rule and do not expect to incur any significant additional costs to comply with this regulation. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, allowing PIPP to be in compliance with MATS.

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 and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units, 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 in February 2016, the Supreme Court stayed the effectiveness of the Clean Power Plan until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. In addition, in February 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 D.C. Circuit Court of Appeals heard the case in September 2016.

The final rule for existing fossil-fueled generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce 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. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. 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. We continue to evaluate possible reduction opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions, given the uncertain future of the Clean Power Plan and current fuel and technology markets. Our evaluation to date indicates that the Clean Power Plan, as well as current fuel markets and advances in technology, are not expected to result in significant additional compliance costs, including capital expenditures, but could impact how we operate our existing fossil-fueled power plants and biomass facility.

However, the timelines for the 2022 through 2029 interim goals and the 2030 final goal for states, as well as all other aspects of the rule, likely will be changed due to the stay and subsequent legal proceedings. With the new Federal Executive Administration as of January 2017, the Clean Power Plan, or its successor, could be significantly changed from the final rule of October 2015. Notwithstanding the potential changes to the Clean Power Plan, addressing climate change is an integral component of our strategic planning process. We continue to reshape our portfolio of electric generation facilities with investments that will improve our environmental performance, including reduced GHG intensity of our operating fleet. As the regulation of GHG emissions takes shape, our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO2 reduction goal, such as increased utilization of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.

Draft Federal Plan and Model Trading Rules (Model Rules) 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 reconsideration of the EPA's final standards for existing, as well as for new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly asked the EPA to consider revising the state goal for existing units to reflect the 2013

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retirement of the Kewaunee Power Station, which could lower the state's CO2 equivalent reduction goal by about 10%. In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. The EPA has not issued decisions yet regarding the above referenced petitions for reconsideration of the final EPA standards for existing generating units. In December 2016, the EPA withdrew the draft Model Rules and accompanying draft documents from the review process and made working drafts available to the public. They are not final documents, are not signed by the Administrator, and will not be published in the Federal Register. The EPA’s docket will remain open, with the potential for completing the agency’s work on these materials and finalizing them at a later date.

We are required to report our CO2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2015, we reported aggregated CO2 equivalent emissions of approximately 25.3 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 23.9 million metric tonnes to the EPA for 2016. 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 2015, we reported aggregated CO2 equivalent emissions of approximately 3.8 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 3.7 million metric tonnes to the EPA for 2016.

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 (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS 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 satisfy the IM BTA requirements. 

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 intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for PWGS, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8. 

During 2017 and 2018, we will continue 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. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 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. Entrainment studies were recently completed at PIPP. See UMERC discussion in Note 20, Regulatory Environment, regarding the potential retirement of PIPP.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

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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. This rule is being litigated in the United States Court of Appeals for the Fifth Circuit and may result in changes to the discharge requirements. The WDNR and MDEQ will continue to modify the state rules as necessary 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 require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site 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 required by the new rule, and modifications will be required at OC 7, OC 8, and the Pleasant Prairie units. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $55 million to $75 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See UMERC discussion in Note 20, Regulatory Environment, regarding the potential retirement of PIPP.

Land Quality

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.

We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31:
(in millions) 2016 2015
Regulatory assets $29.9
 $16.9
Reserves for future remediation 19.0
 5.6
Renewables, Efficiency, and Conservation

Wisconsin Legislation

In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. We have achieved a renewable energy percentage of 8.27% and met our compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolios and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual operating revenues.

Michigan Legislation

In 2008, Michigan enacted Act 295, which required 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. In December 2016, Michigan revised this legislation with Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the

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requirement to 15.0% for 2021. We were in compliance with these requirements as of December 31, 2016. The revised legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

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 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 Paris Generating Station Units 1 and 4. Act 91, along with a new construction permit, allowed those units to restart after a temporary outage. 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. The Sierra Club has withdrawn the contested case hearing request, thereby concluding this matter.

NOTE 17—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, 2016
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $6.0
 $0.8
 $—
 $6.8
   Petroleum products contracts 0.2
 —
 —
 0.2
FTRs —
 —
 3.1
 3.1
Coal contracts —
 1.9
 —
 1.9
Total derivative assets $6.2
 $2.7
 $3.1
 $12.0
         
Derivative liabilities        
Natural gas contracts $0.1
 $—
 $—
 $0.1
   Petroleum products contracts 0.1
 —
 —
 0.1
Coal contracts —
 0.5
 —
 0.5
Total derivative liabilities $0.2
 $0.5
 $—
 $0.7

  December 31, 2015
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $0.5
 $—
 $—
 $0.5
   Petroleum products contracts 1.2
 —
 —
 1.2
FTRs —
 —
 1.6
 1.6
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


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The derivative assets and liabilities listed in the tables above include options, 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 18, Derivative Instruments, for more information.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
(in millions) 2016 2015 2014
Balance at the beginning of the period $1.6
 $7.0
 $3.5
Purchases 8.1
 3.9
 15.6
Settlements (6.6) (9.3) (12.1)
Balance at the end of the period $3.1
 $1.6
 $7.0

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.

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, 2016 December 31, 2015
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock $30.4
 $28.8
 $30.4
 $27.3
Long-term debt 2,661.1
 2,923.4
 2,658.8
 2,888.2

NOTE 18—DERIVATIVE INSTRUMENTS

The following table shows our derivative assets and derivative liabilities:
  December 31, 2016 December 31, 2015
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current        
   Natural gas contracts $6.3
 $0.1
 $0.5
 $8.1
   Petroleum products contracts 0.2
 0.1
 0.9
 3.3
   FTRs 3.1
 —
 1.6
 —
   Coal contracts 1.5
 0.5
 1.7
 3.4
   Total other current $11.1
 $0.7
 $4.7
 $14.8
         
Other long-term        
   Natural gas contracts $0.5
 $—
 $—
 $1.3
   Petroleum products contracts —
 —
 0.3
 1.1
   Coal contracts 0.4
 —
 0.3
 4.2
   Total other long-term $0.9
 $—
 $0.6
 $6.6
Total $12.0
 $0.7
 $5.3
 $21.4

Our estimated notional sales volumes and realized gains (losses) were as follows:
  December 31, 2016 December 31, 2015 December 31, 2014
(in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains
Natural gas contracts 35.3 Dth $(12.3) 24.0 Dth $(12.6) 21.4 Dth $4.0
Petroleum products contracts 10.3 gallons (2.6) 4.0 gallons (0.2) 9.2 gallons 0.5
FTRs 25.3 MWh 7.3
 22.8 MWh 3.2
 26.1 MWh 12.7
Total   $(7.6)   $(9.6)   $17.2

At December 31, 2016, we had received cash collateral of $3.4 million in our margin accounts, and at December 31, 2015, we had posted cash collateral of $14.9 million in our margin accounts.


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The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
  December 31, 2016 December 31, 2015
(in millions) 
Derivative
Assets
 Derivative Liabilities 
Derivative
Assets
 Derivative Liabilities
Gross amount recognized on the balance sheet $12.0
 $0.7
 $5.3
 $21.4
Gross amount not offset on the balance sheet * (3.6) (0.2) (0.7) (13.5)
Net amount $8.4
 $0.5
 $4.6
 $7.9

*Includes cash collateral received of $3.4 million at December 31, 2016, and cash collateral posted of $12.8 million at December 31, 2015.

NOTE 19—VARIABLE INTEREST ENTITIES

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis. This ASU focuses on the consolidation analysis for companies that are required to evaluate whether they should consolidate certain legal entities. It emphasizes the risk of loss when determining a controlling financial interest and amends the guidance for assessing how related party relationships affect the consolidation analysis of variable interest entities. We adopted the standard upon its effective date in the first quarter of 2016, and our adoption resulted in no changes to our disclosures or financial statement presentation.

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.

We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, 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

As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. Prior to the transfer, ATC was a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 5, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheets at December 31, 2016, included our equity investment and accounts payable. At December 31, 2016, and 2015, our equity investment was $402.0 million and $382.2 million, respectively, which approximated our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $20.0 million and $19.9 million of accounts payable due to ATC at December 31, 2016, and 2015, respectively, 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 five years. We have examined the risks of the entity, including operations, 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 $85.3 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 this contract for the years ended December 31, 2016, 2015, and 2014 were $54.2 million, $53.6 million, and $53.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

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NOTE 20—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 reflected 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. As a result of the sale of the MCPP, we no longer have any Milwaukee County steam utility customers. See Note 3, Dispositions, for more information about the sale of the MCPP.

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 included higher fixed charges to better match the 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 record SSR revenues of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference is 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 is deferred and will be 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, Acquisitions, 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.

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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 reflected 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 ERGS units were prudently incurred, and it approved the recovery of the majority of these costs in rates.

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand-alone utility in the Upper Peninsula of Michigan and it became operational effective January 1, 2017. This utility holds our and WPS's electric and natural gas distribution assets located in the Upper Peninsula.

In August 2016, WEC Energy Group entered into an agreement with the Tilden Mining Company (Tilden) under which it will purchase electric power from UMERC for its iron ore mine for 20 years. The agreement also calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation located in the Upper Peninsula of Michigan. On January 30, 2017, UMERC filed an application with the MPSC for a certificate of necessity to begin construction of the proposed generation. The estimated cost of this project is approximately $265 million ($275 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain our customer until this new generation begins commercial operation.

NOTE 21—SEGMENT INFORMATION

During the second quarter of 2016, we reorganized our business segments to reflect our new internal organization and management structure. All prior period amounts impacted by this change were reclassified to conform to the new presentation.

We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2016, we reported two segments, which are described below.

Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, northern Wisconsin, and the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden Mining Company. See Note 4, Related Parties, and Note 20, Regulatory Environment, for additional information. Our electric utility operations also include our steam operations which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are 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.

At December 31, 2016, our other segment included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and Bostco, our non-utility subsidiary, that develops and invests in real estate. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information.


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All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2016, 2015, and 2014.
2016 (in millions)
 Utility Other Wisconsin Electric Power Company Consolidated
Operating revenues $3,792.8
 $—
 $3,792.8
Other operation and maintenance 1,430.2
 —
 1,430.2
Depreciation and amortization 325.4
 —
 325.4
Operating income 629.5
 —
 629.5
Equity in earnings of transmission affiliate —
 55.5
 55.5
Interest expense 116.6
 1.0
 117.6
Capital expenditures 468.9
 0.6
 469.5
Total assets 12,945.1
 426.4
 13,371.5

2015 (in millions)
 Utility Other 
Wisconsin Electric Power
Company Consolidated
Operating revenues $3,854.1
 $—
 $3,854.1
Other operation and maintenance 1,384.9
 —
 1,384.9
Depreciation and amortization 304.0
 —
 304.0
Operating income 648.9
 —
 648.9
Equity in earnings of transmission affiliate —
 47.8
 47.8
Interest expense 117.7
 1.3
 119.0
Capital expenditures 518.8
 0.4
 519.2
Total assets 12,727.6
 412.0
 13,139.6

2014 (in millions)
 Utility Other 
Wisconsin Electric Power
Company Consolidated
Operating revenues $4,059.4
 $—
 $4,059.4
Other operation and maintenance 1,356.4
 —
 1,356.4
Depreciation and amortization 278.3
 —
 278.3
Operating income 650.4
 —
 650.4
Equity in earnings of transmission affiliate —
 57.9
 57.9
Interest expense 114.9
 1.6
 116.5
Capital expenditures 561.8
 —
 561.8
Total assets 12,195.9
 401.3
 12,597.2

NOTE 22—QUARTERLY FINANCIAL INFORMATION (Unaudited)
(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total
2016          
Operating revenues $975.5
 $877.2
 $1,023.8
 $916.3
 $3,792.8
Operating income 181.5
 146.9
 196.4
 104.7
 629.5
Net income attributed to common shareholder 107.3
 82.6
 115.2
 59.2
 364.3
           
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

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. Several amendments were issued subsequent to the standard to clarify the

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guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. This method will result in a cumulative-effect adjustment that will be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. Disclosures in 2018 will include a reconciliation of results under the new revenue guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.

We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider our tariff sales, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry, including the impacts of the new guidance on our ability to recognize revenue for certain contracts where collectability is uncertain and the accounting for contributions in aid of construction (CIAC). We currently account for CIAC funds received from customers and/or developers outside of revenue, as a reduction to property, plant, and equipment. The final resolution of these issues could impact our current accounting policies and revenue recognition.

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. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. 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, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP.  We are currently assessing the effects this guidance may have on our financial statements.

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Under this ASU, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement, the tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur, and excess tax benefits are recognized in the current period regardless of whether the benefit reduces taxes payable. On the cash flow statement, excess tax benefits are classified along with other income tax cash flows as an operating activity, and cash paid by an employer when directly withholding shares for tax purposes is classified as a financing activity. We adopted this guidance effective January 1, 2017, and do not expect it to impact our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for
fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally

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delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.

Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We are currently assessing the effects this guidance may have on our financial statements.


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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 (1992)(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, 2013.2016.

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 20132016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION

NoneNone.




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2013 Form 10-K


PART III


ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT
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 24, 201427, 2017 (the "2014"2017 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 20142017 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 WE, 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 20142017 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.



101Wisconsin Electric Power Company
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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 20142017 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 20142017 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, 2013.
Report of Independent Registered Public Accounting Firm.
 
66
Consolidated Balance Sheets at December 31, 2013 and 2012.
6747
    
 
Consolidated Income Statements for the three years ended December 31, 2016, 2015, and 2014.
48
Consolidated Balance Sheets at December 31, 2016 and 2015.
49
Consolidated Statements of Cash Flows for the three years ended December 31, 2013.2016, 2015, and 2014.
 
6950
    
 
Consolidated Statements of Capitalization atEquity for the three years ended December 31, 20132016, 2015, and 2012.2014.
 
7051
    
 
Consolidated Statements of Common Equity for the three years endedCapitalization at December 31, 2013.2016 and 2015.
 
7152
    
 
Notes to Consolidated Financial Statements.
 
7253
2.Financial Statement Schedules Included in Part IV of This Report
    
 Report of Independent Registered Public Accounting Firm.
99

2
FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT
Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2013.2016, 2015, and 2014.
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.


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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

ITEM 16. FORM 10-K SUMMARY

None.


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2013 Form 10-K

SCHEDULE IISCHEDULE II
WISCONSIN 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, 2013 $36.7
 $31.4
 $2.7
 $(31.1) $39.7
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
Allowance for Doubtful Accounts
(in millions)
 Balance at Beginning of Period 
Expense (1)
 Deferral 
Net Write-offs (2)
 Balance at End of Period
December 31, 2016 $43.0
 $31.1
 $(5.7) $(27.5) $40.9
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

(1)
Net of recoveries

(2)
Represents amounts written off to the reserve, net of adjustments to regulatory assets.

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2013 Form 10-K


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

  WISCONSIN ELECTRIC POWER COMPANY
   
 By  /s/GALE E. KLAPPA                                             ALLEN L. LEVERETT
Date:February 27, 201428, 2017Gale E. Klappa,Allen L. Leverett, 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                                                                   ALLEN L. LEVERETT February 27, 201428, 2017
Gale E. Klappa,Allen L. Leverett, Chairman of the Board President and Chief Executive  
Executive Officer and Director -- Principal Executive Officer  
   
/s/ SCOTT J. PATRICK KEYESLAUBER February 27, 201428, 2017
Scott J. Patrick Keyes,Lauber, Executive Vice President and Chief  
Financial Officer and Director -- Principal Financial Officer  
   
/s/STEPHEN P. DICKSON                                                         WILLIAM J. GUC February 27, 201428, 2017
Stephen P. Dickson,William J. Guc, Vice President and  
Controller -- Principal Accounting Officer  
   
/s/JOHN F. BERGSTROM                                                          J. KEVIN FLETCHER February 27, 201428, 2017
John F. Bergstrom,J. Kevin Fletcher, Director  
   
/s/BARBARA L. BOWLES                                                         SUSAN H. MARTIN February 27, 201428, 2017
Barbara L. Bowles, Director
/s/PATRICIA W. CHADWICK                                                   February 27, 2014
Patricia W. Chadwick, Director
/s/CURT S. CULVER                                                                   February 27, 2014
Curt S. Culver, Director
/s/THOMAS J. FISCHER                                                             February 27, 2014
Thomas J. Fischer, Director
/s/HENRY W. KNUEPPELFebruary 27, 2014
Henry W. Knueppel, Director
/s/ULICE PAYNE, JR.                                                                 February 27, 2014
Ulice Payne, Jr., Director
/s/MARY ELLEN STANEKFebruary 27, 2014
Mary Ellen Stanek,Susan H. Martin, Director  


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2013 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, 20132016
 
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,WE, as amended and restated effective January 10, 1995. (Exhibit (3)-1 to Wisconsin Electric Power Company'sWE's 12/31/94 Form 10-K.)
    
  3.2*Bylaws of Wisconsin Electric Power Company,WE, as amended to May 1, 2000. (Exhibit 3.1 to Wisconsin Electric Power Company'sWE'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.to WE's 12/31/16 Form 10-K.)
    
  IndentureIndentures and Securities Resolutions:
    
  4.2*Indenture for Debt Securities of Wisconsin Electric Power CompanyWE (the "Wisconsin Electric"WE Indenture"), dated December 1, 1995. (Exhibit (4)-1 to Wisconsin Electric'sWE's 12/31/95 Form 10-K.)
    
  4.3*Securities Resolution No. 1 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated December 5, 1995. (Exhibit (4)-2 to Wisconsin Electric'sWE's 12/31/95 Form 10-K.)
    
  4.4*Securities Resolution No. 3 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated May 27, 1998. (Exhibit (4)-1 to Wisconsin Electric'sWE's 06/30/98 Form 10-Q.)
    
  4.5*Securities Resolution No. 5 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of May��May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to Wisconsin Electric'sWE's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)
    
  4.6*Securities Resolution No. 7 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of November 2, 2006. (Exhibit 4.1 to Wisconsin Electric'sWE's 11/02/06 Form 8-K.)
    
  4.7*Securities Resolution No. 810 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of December 8, 2009. (Exhibit 4.1 to WE's 12/08/09 Form 8-K.)
4.8*Securities Resolution No. 11 of WE under the WE Indenture, dated as of September 25, 2008.7, 2011. (Exhibit 4.1 to Wisconsin Electric'sWE's 09/25/0807/11 Form 8-K.)
4.9*Securities Resolution No. 12 of WE under the WE Indenture, dated as of December 5, 2012. (Exhibit 4.1 to WE's 12/05/12 Form 8-K.)
4.10*Securities Resolution No. 13 of WE under the WE Indenture, dated as of June 10, 2013. (Exhibit 4.1 to WE’s 06/10/13 Form 8-K.)
4.11*Securities Resolution No. 14 of WE under the WE Indenture, dated as of May 12, 2014. (Exhibit 4.1 to WE's 05/12/14 Form 8-K.)
4.12*Securities Resolution No. 15 of WE under the WE Indenture, dated as of May 14, 2015. (Exhibit 4.1 to WE's 05/14/15 Form 8-K.)
    

2016 Form 10-KE-195Wisconsin Electric Power Company
Table of Contents
2013 Form 10-K


Number Exhibit
  
4.8*4.13*Securities Resolution No. 916 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of December 8, 2008.November 13, 2015. (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*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*Securities Resolution No. 12 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 5, 2012. (Exhibit 4.1 to Wisconsin Electric's 12/05/12 Form 8-K.)
4.12*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 06/10/13WE'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, 2005.2017. (Exhibit 10.910.1 to WisconsinWEC Energy Corporation'sGroup's 12/31/0816 Form 10-K (File No. 001-09057).)** See Note.
    
  10.2*Service Agreement, dated April 25, 2000, between Wisconsin Electric Power Company and Wisconsin Gas LLC. (Exhibit 10.32 to WisconsinLegacy WEC Energy Corporation's 12/31/00 Form 10-K (File No. 001-09057).)
10.3*Service Agreement, dated December 29, 2000, between Wisconsin Electric Power Company and American Transmission Company LLC. (Exhibit 10.33 to Wisconsin Energy Corporation's 12/31/00 Form 10-K (File No. 001-09057).)
10.4*Group Executive Deferred Compensation Plan, of Wisconsin Energy Corporation, as amendedAmended and restatedRestated as of July 23, 2004 (including amendments approved effective as of November 2, 2005) (the "Legacy EDCP")January 1, 2016. (Exhibit 10.2 to WisconsinWEC Energy Corporation's 09/30/05Group's 12/31/15 Form 10-Q10-K (File No. 001-09057).)** See Note
    
  10.5*10.3*First Amendment to the Legacy EDCP, effectiveWEC Energy Group Executive Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2005.2017. (Exhibit 10.1210.3 to WEC Energy Group's 12/31/16 Form 10-K (File No. 001-09057).)** See Note.
10.4*Legacy Wisconsin Energy Corporation'sCorporation Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2017. (Exhibit 10.4 to WEC Energy Group's 12/31/0816 Form 10-K (File No. 001-09057).)** See Note.
10.5*WEC Energy Group Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2017. (Exhibit 10.5 to WEC Energy Group's 12/31/16 Form 10-K (File No. 001-09057).)** See Note.
    
  10.6*WisconsinWEC Energy Corporation Executive Deferred CompensationGroup Non-Qualified Retirement Savings Plan, amendedAmended and restated effectiveRestated Effective as of September 8, 2009.January 1, 2017. (Exhibit 10.910.6 to WisconsinWEC Energy Corporation'sGroup's 12/31/1116 Form 10-K (File No. 001-09057).)** See Note.
    
  10.7*Directors' Deferred CompensationWEC Energy Group Short-Term Performance Plan, of Wisconsin Energy Corporation, as amended and restated effective as of MayJanuary 1, 2004 (the "Legacy DDCP").2016. (Exhibit 10.310.2 to WisconsinWEC Energy Corporation's 06/30/04Group's 12/03/15 Form 10-Q8-K (File No. 001-09057).)** See Note.

 E-2Wisconsin Electric Power Company
2013 Form 10-K

NumberExhibit
   
  10.8*First AmendmentWisconsin Energy Corporation 2014 Rabbi Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 23, 2015, regarding the trust established to provide a source of funds to assist in meeting the Legacy DDCP, effective as of January 1, 2005.liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.1510.13 to Wisconsin Energy Corporation's 12/31/0814 Form 10-K (File No. 001-09057).)** See Note.
    
  10.9*Wisconsin Energy Corporation Directors' Deferred Compensation Plan, effective as of January 1, 2005. (Exhibit 10.16 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No.001-09057).)** See Note.
10.10*Wisconsin Energy Corporation Death Benefit Only Plan, as amended and restated as of July 22, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/10 Form 10-Q (File No. 001-09057).)** See Note.
10.11*Wisconsin Energy Corporation Short-Term Performance Plan, as amended and restated effective as of January 1, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/03/09 Form 8-K (File No. 001-09057).)** See Note.
10.12*Wisconsin Energy Corporation Amended and Restated Executive Severance Policy, effective as of January 1, 2008. (Exhibit 10.18 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.
10.13*Restated Non-Qualified Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 11, 2004 (the “Non-Qualified Trust Agreement”), regarding trust established to provide a source of funds to assist in meeting of the liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.16 to Wisconsin Energy Corporation's 12/31/07 Form 10-K (File No. 001-09057).)** See Note.
10.14*First Amendment to the Non-Qualified Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company, effective as of July 23, 2013. (Exhibit 10.1 to Wisconsin Energy Corporation’s 09/30/13 Form 10-Q (File No. 001-09057).)**See Note.
10.15*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).)
10.16*Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Gale E. Klappa, dated as of December 29, 2008. (Exhibit 10.25 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.
    
  10.17*10.10*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.
    
  10.18*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*10.11*Terms of Employment for J. Patrick Keyes. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/12 Form 10-Q (File No. 001-09057).)** See Note.
    

E-3Wisconsin Electric Power Company
2013 Form 10-K

NumberExhibit
  
10.20*10.12*Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of December 20, 2010. (Exhibit 10.20 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.
    
  10.21*10.13*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*10.14*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*10.15*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.
10.24*Separation Agreement and General Release between Wisconsin Energy Corporation and Kristine A. Rappé, effective December 28, 2012. (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)**See Note.
10.25*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.
10.26*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.
10.27*Amended and Restated Non-Compete and Special Severance Tax Protection Agreement between Wisconsin Energy Corporation and Stephen P. Dickson, effective as of January 1, 2008. (Exhibit 10.33 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.
10.28*
Letter Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q
(File (File No. 001-09057).)** See Note.
    

2016 Form 10-K96Wisconsin Electric Power Company
Table of Contents

NumberExhibit
  10.29*10.16*Letter Agreement by and between Wisconsin Energy Corporation and Joseph Kevin Fletcher, dated as of August 17, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/11 Form 10-Q (File No. 001-09057).)** See Note.
    
  10.30*10.17*1993 Omnibus Stock Incentive Plan, amendedAmended and restated effectiveRestated Effective as of May 5, 2011, as approved by WisconsinJanuary 1, 2016. (Exhibit 10.19 to WEC Energy Corporation's stockholders at its 2011 annual meeting of stockholders. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/11Group's 12/31/15 Form 10-Q10-K (File No. 001-09057).)** See Note.
    
  10.31*10.18*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.
    
  10.32*10.19*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.

 E-4Wisconsin Electric Power Company
2013 Form 10-K

NumberExhibit
   
  10.33*10.20*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.
    
  10.34*10.21*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.
    
  10.35*10.22*WisconsinWEC Energy CorporationGroup Performance Unit Plan, amended and restated effective as of January 1, 2010.2017. (Exhibit 10.210.1 to WisconsinWEC Energy Corporation'sGroup's 12/03/0901/16 Form 8-K (File No. 001-09057).)** See Note.
    
  10.36*10.23*Form of Award of Performance Units under the Wisconsin Energy Corporation Performance Unit Plan.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 12/06/0404/14 Form 8-K (File No. 001-09057).)** See Note.
    
  10.37*10.24*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.
10.25*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.
10.26*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.
10.27*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'sWE's 06/30/03 Form 10-Q.)
    
  10.38*10.28*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'sWE's 06/30/03 Form 10-Q.)
    
  10.39*10.29*Elm Road I Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)
    
  10.40*10.30*Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)
    
  10.41*10.31*
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).)

    
  10.42*10.32*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).)
10.33*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.

2016 Form 10-K97Wisconsin Electric Power Company
Table of Contents

NumberExhibit
    
  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.

E-5Wisconsin Electric Power Company
2013 Form 10-K

NumberExhibit
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


2016 Form 10-KE-698Wisconsin Electric Power Company