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, 20142017

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, or emerging growth company. See the definitions of "large accelerated filer," "accelerated filer"filer," "smaller reporting company," and "smaller reporting"emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

                                 Large accelerated filer [ ]                                 Accelerated filer [  ]
Large accelerated filer [ ]Accelerated filer [  ]
Non-accelerated filer [X] (Do not Smaller reporting company [  ]
check if a smaller reporting company)
Smaller reporting company [  ]
Emerging growth company [  ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

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, 20142017 (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, 2015):

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, 2018


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,Shareholders, to be held on April 30, 2015,26, 2018, are incorporated by reference into Part III hereof.


2014 Form 10-K


WISCONSIN ELECTRIC POWER COMPANY
FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2014



WISCONSIN ELECTRIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2017
TABLE OF CONTENTS
TABLE OF CONTENTS
ItemPage
  Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
1
PART I
3
ITEM 1.
BUSINESS
3
 
A.
INTRODUCTION
3
1.       Business
10B.
UTILITY SEGMENT
3
C.
OTHER SEGMENT
12
D.
REGULATION
12
E.
ENVIRONMENTAL COMPLIANCE
14
F.
EMPLOYEES
15
ITEM 1A.
RISK FACTORS
16
ITEM 1B.
UNRESOLVED STAFF COMMENTS
25
ITEM 2.
PROPERTIES
26
ITEM 3.
LEGAL PROCEEDINGS
27
ITEM 4.
MINE SAFETY DISCLOSURES
27
EXECUTIVE OFFICERS OF THE REGISTRANT
28
PART II
30
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
30
ITEM 6.
SELECTED FINANCIAL DATA
31
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
32
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
49
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
50
A.
Report of Independent Registered Public Accounting Firm
50
B.
Consolidated Income Statements
51
C.
Consolidated Balance Sheets
52
D.
Consolidated Statements of Cash Flows
53
E.
Consolidated Statements of Equity
54
F.
Consolidated Statements of Capitalization
55
G.
Notes to Consolidated Financial Statements
56
  
1A.    Risk Factors
Note 1
23Summary of Significant Accounting Policies
56
  
1B.    Unresolved Staff Comments
Note 2
31Acquisitions
62
  
2.       Properties
Note 3
32Dispositions
62
  
3.       Legal Proceedings
Note 4
33Related Parties
63
  
4.       Mine Safety Disclosures
Note 5
34Regulatory Assets and Liabilities
65
  
Executive Officers of the Registrant
Note 6
34Property, Plant, and Equipment
66
  
PART II
Note 7
Asset Retirement Obligations
67
  
5.       Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
          Equity SecuritiesNote 8
35Common Equity
67
  
6.       Selected Financial Data
Note 9
36Preferred Stock
69
  
7.       Management's Discussion and Analysis of Financial Condition and Results of Operations
Note 10
37Short-Term Debt and Lines of Credit
70
  
7A.    Quantitative and Qualitative Disclosures About Market Risk
Note 11
63
8.       Financial Statements and Supplementary Data
64
Consolidated Income Statements
64
Consolidated Balance Sheets -- Assets
65
Consolidated Balance Sheets -- Capitalization and Liabilities
66
Consolidated Statements of Cash Flows
67
Consolidated Statements of Capitalization
68
Consolidated Statements of Common Equity
69
Notes to Consolidated Financial Statements
70
Note ASummary of Significant Accounting Policies
70
Note BRecent Accounting Pronouncements
73
Note CRegulatory Assets and Liabilities
73
Note DProposed Acquisition of Integrys by Wisconsin Energy
74
Note EAsset Retirement Obligations
75
Note FVariable Interest Entities
75
Note GIncome Taxes
75
Note HCommon Equity
78
Note IPreferred Stock
81
Note JLong-Term Debt and Capital Lease Obligations
8170
 
Note K12
Short-Term Debt
Income Taxes
73
Note 13
Fair Value Measurements
75
Note 14
Derivative Instruments
76
Note 15
Employee Benefits
77
Note 16
Investment in American Transmission Company
82
Note 17
Segment Information
82
Note 18
Variable Interest Entities
83
 Note LDerivative Instruments
84

2017 Form 10-K3iWisconsin Electric Power Company
Table of Contents
2014 Form 10-K

TABLE OF CONTENTS - (Cont'd)

Item  Page
Note 19
Commitments and Contingencies
84
 Note MFair Value Measurements
85Note 20
Supplemental Cash Flow Information
88
 Note NBenefits
87Note 21
Regulatory Environment
89
 Note OSegment Reporting
92Note 22
Quarterly Financial Information (Unaudited)
90
 
Note P23
Related Parties
New Accounting Pronouncements
91
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
93
ITEM 9A.
Note Q
CONTROLS AND PROCEDURES
Commitments and Contingencies
93
ITEM 9B.
OTHER INFORMATION
93
PART III
94
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT
94
ITEM 11.
EXECUTIVE COMPENSATION
94
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
94
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
94
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
95
Note RSupplemental Cash Flow Information
PART IV
96
ITEM 15.
Note SSubsequent Event
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
96
Report of Independent Registered Public Accounting Firm
ITEM 16.
97FORM 10-K SUMMARY
9.       Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
98
9A.   Controls and Procedures
98
9B.    Other Information
98
PART III
10.    Directors, Executive Officers and Corporate Governance of the Registrant
99
11.    Executive Compensation
99
12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
         Matters
99
13.    Certain Relationships and Related Transactions, and Director Independence
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
100
14.    Principal Accountant Fees and Services
SIGNATURES
100101
PART IV
15.    Exhibits and Financial Statement Schedules
100
Schedule II - Valuation and Qualifying Accounts
102
Signatures
103
Exhibit Index
E-1


2017 Form 10-K4iiWisconsin Electric Power Company
Table of Contents
2014 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
BluewaterBluewater Natural Gas Holding, 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
WisparkWispark LLC
WPSWisconsin Public Service Corporation
   
Significant Assets
OC 1Oak Creek expansion Unit 1
OC 2Oak Creek expansion Unit 2
PIPPPresque Isle Power Plant
PSGSParis Generating Station
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
IRSUnited States Internal Revenue Service
MDEQ Michigan Department of Environmental Quality
MPSC Michigan Public Service Commission
PSCW Public Service Commission of Wisconsin
SEC Securities and Exchange Commission
WDNR Wisconsin Department of Natural Resources
   
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
CPPClean Power Plan
CSAPR Cross-State Air Pollution Rule
EMEntrainment Mortality
GHG Greenhouse Gas
IMImpingement Mortality

5Wisconsin Electric Power Company
2014 Form 10-K

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
MATSMercury and Air Toxics Standards
NAAQS National Ambient Air Quality Standards
NOx
NOx		 Nitrogen Oxide
PM2.5
Fine Particulate Matter
PSDPrevention of Significant Deterioration
SIPState Implementation Plan
SO2
 Sulfur Dioxide
WPDES Wisconsin Pollutant Discharge Elimination System
Measurements
DthDekatherm
MWMegawatt
MWhMegawatt-hour
 

2017 Form 10-KiiiWisconsin Electric Power Company
Table of Contents

Other Terms and Abbreviations
AQCSAIA Air Quality Control SystemAffiliated Interest Agreement
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 Circuit
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
HSR ActHart-Scott-Rodino Antitrust Improvements Act of 1976
IntegrysIntegrys Energy Group, Inc.
LMP Locational Marginal Price
Merger AgreementMCPP Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys and Wisconsin Energy CorporationMilwaukee County Power Plant
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
Tax LegislationTax Cuts and Jobs Act of 2017
TildenTilden Mining Company
Treasury Grant Section 1603 Renewable Energy Treasury Grant
UPPCOVAPP Upper PeninsulaValley Power Company
Measurements
BtuBritish Thermal Unit(s)
DthDekatherm(s) (One Dth equals one million Btu)
kWKilowatt(s) (One kW equals one thousand Watts)
kWhKilowatt-hour(s)Plant


2017 Form 10-K6ivWisconsin Electric Power Company
Table of Contents
2014 Form 10-K

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


7Wisconsin Electric Power Company
2014 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," "will" or similar terms"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; availability ofdamage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric generating facilities; unscheduled generation outages,transmission or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipatednatural gas pipeline system constraints;

Factors affecting the demand for electricity and natural 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, 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;

The uncertainty surrounding the recently enacted Tax Legislation, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and its impact, if any, on our credit ratings;

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 interpretation of permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;

Factors affecting the implementation of WEC Energy Group's generation reshaping plan, including related regulatory decisions, the cost orof materials, supplies, and labor, and the feasibility of competing projects;

Increased pressure on us by investors and other stakeholder groups to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases;

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 affecting the demand for electricity and natural gas, including weather and other natural phenomena; general economic conditions and, in particular, the economic climate in our service territories; customer growth and declines; customer business conditions, including demand for their products and services; energy conservation efforts; and customers moving to self-generation.

Timing, resolution and impact of rate cases and negotiations.

The impact across our service territories of the continued adoption of distributed generation by our electric customers.

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

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

The impact of recent and future federal, state and local legislative and regulatory changes, including any changes in rate-setting policies or procedures; regulatory initiatives regarding deregulation and restructuring of the electric and/or gas utility industry; transmission or distribution system operation and/or administration initiatives; any required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities or cyber security threats; the regulatory approval process for new generation and transmission facilities and new pipeline construction; adoption of new, or changes in existing, environmental, federal and state energy, tax and other laws and regulations to which we are, or may become, subject; changes in

2017 Form 10-K81Wisconsin Electric Power Company
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION - (Cont'd)2014 Form 10-K

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).

CurrentChanges in credit ratings, interest rates, and future litigation, regulatory investigations, proceedings or inquiries.

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

Other factors affecting our ability to access the capital markets, including general capital market conditions;caused by volatility in the global credit markets, our capitalization structure;structure, and market perceptions of the utility industry or us;

Costs and our credit ratings.effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;

The direct or indirect effect onrisk of financial loss, including increases in bad debt expense, associated with the inability of our business resulting from terrorist incidentscustomers, counterparties, and the threat of terrorist incidents, including cyber intrusion.

Inflation rates.

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

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

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

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

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 direct or indirect effect on our business resulting from terrorist attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns;

The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

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

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

Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets;

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

The ability to obtainmaintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, while both integrating and retain short- and long-term contractscontinuing to consolidate WEC Energy Group's enterprise systems with wholesale customers.those of its other utilities;

Incidents affecting the U.S. electric grid or operationThe effect of generating facilities.

Foreign governmental, economic, politicalaccounting pronouncements issued periodically by standard-setting bodies; and currency risks.

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.


2017 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 usedWisconsin and serve customers in this document,Wisconsin and served customers in the terms Wisconsin Electric,Upper Peninsula of Michigan through December 31, 2016. Effective January 1, 2017, we transferred our electric customers and distribution assets located in the Company, our, us or we referUpper Peninsula of Michigan to Wisconsin Electric Power Company and its subsidiary, Bostco LLC (Bostco).UMERC, a stand-alone utility. UMERC became operational effective January 1, 2017. See Note 21, Regulatory Environment, for more information on UMERC.

We conduct our operationsbusiness primarily through our utility reportable segment. Effective January 1, 2017, we transferred our investment in three reportable segments: an electric utility segment, a natural gas utility segmentATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information. In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and a steam utility segment. We serve approximately 1,133,600 electric customers in Wisconsin andresidential space. See Note 3, Dispositions, for more information on the Upper Peninsulasale of Michigan, approximately 475,100 gas customers in Wisconsin and approximately 440 steam customers in metropolitan Milwaukee, Wisconsin. the remaining real estate holdings of Bostco.

For further financialmore information about our business segments,utility operations, including financial and geographic information, see Note 17, Segment Information, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note O -- Segment Reporting in the Notes to Consolidated Financial Statements in Item 8.– Results of Operations.

Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas), a natural gas distribution utility, which serves customers throughout Wisconsin; and W.E. Power, LLC (We Power), a non-utility company that was formed in 2001 to design, construct, own and lease to us the generating capacity included in Wisconsin Energy's Power the Future (PTF) strategy. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies."Acquisition

Proposed Acquisition: On June 22, 2014,29, 2015, Wisconsin Energy entered into an agreementCorporation acquired 100% of the outstanding common shares of Integrys and changed its name to acquire IntegrysWEC Energy Group, Inc. (Integrys). The proposed acquisition is scheduled to close in the second half of 2015, and is subject to the receipt of various approvals. The combined company will serve approximately 1.5 million electric customers, 2.8 million gas customers and own approximately 60% of ATC. For additional information on this acquisition, see Note D -- Proposed Acquisition of Integrys by Wisconsin Energy in the Notes to Consolidated Financial Statements in Item 8.2, Acquisitions.

Bostco is our non-utility subsidiary that develops and invests in real estate. As of December 31, 2014, Bostco had $28.4 million of assets.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, and serve an iron ore mine customer, Tilden, in the Upper Peninsula of Michigan.

We participateThrough December 31, 2016, we served electric customers in the Midcontinent Independent System Operator (MISO) Energy Markets. The competitivenessUpper Peninsula of Michigan. Effective January 1, 2017, we transferred our generation offeredelectric customers (other than Tilden) and electric distribution assets located in the MISOUpper Peninsula of Michigan to UMERC, a stand-alone utility owned by WEC Energy Markets affects how our generating units are dispatchedGroup. See Note 4, Related Parties, and how we buyNote 21, Regulatory Environment, for more information. UMERC currently meets its market obligations through power purchase agreements with us and sell power. For further information, see Factors Affecting Results, Liquidity and Capital ResourcesWPS. UMERC will begin to generate electricity when its new generation solution in Item 7.the Upper Peninsula of Michigan begins commercial operation, which is expected to occur in 2019.


2017 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) 2017 2016 2015
Operating revenues      
Residential $1,178.4
 $1,243.3
 $1,207.6
Small commercial and industrial 1,015.9
 1,046.1
 1,036.8
Large commercial and industrial 657.3
 699.3
 727.7
Other 21.2
 21.0
 22.1
Total retail revenues 2,872.8
 3,009.7
 2,994.2
Wholesale 118.8
 88.7
 101.4
Resale 238.0
 224.4
 228.2
Steam 23.3
 27.2
 41.0
Other operating revenues * 83.3
 90.6
 89.6
Total operating revenues $3,336.2
 $3,440.6
 $3,454.4

*Includes SSR revenues, rent income, and ancillary revenues, partially offset by revenues from Tilden 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 which includeincluded supply and distribution sales to our retail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier, totaled approximately 35.1 millionsupplier. In 2017, retail electric revenues accounted for 86.1% of total electric operating revenues, while wholesale and resale electric revenues accounted for 10.7% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Operating Income for information on MWh during 2014 and approximately 33.0 million MWh during 2013. We had approximately

10Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2014 Form 10-K

1,133,600 electric customers as of December 31, 2014 and 1,128,300 electric customers as of December 31, 2013.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. Although we no longer provide electric service in certain territories in the state of Michigan, pursuantwe continue, on an interim basis, to franchises granted by municipalities. provide service to the Tilden mine located in the Upper Peninsula of Michigan. See the discussion below under the heading "Large Electric Retail Customers."

We alsobuy 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 whether we buy and sell power. For more information, see 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 Growth:Forecast

Our service territory experienced steadyslightly lower weather-normalized retail electric sales in 2014 after accounting for changes associated with2017, driven by the transfer of customers switching to alternative electric suppliers. Assuming continuing improvement in the economy over the five-yearUMERC and lower use per residential customer. We currently forecast horizon, we presently anticipate that total retail electric kWh sales volumes and the associated peak electric demand, will grow at a compound annual rateexcluding the Tilden mine located in the Upper Peninsula of about 0.5%Michigan, to remain flat over the next five years,. These estimates assume assuming normal weather.weather. The Tilden mine will no longer be a retail customer of ours once UMERC's new generation solution in the Upper Peninsula of Michigan begins commercial operation, which is expected to occur in 2019.


2017 Form 10-K4Wisconsin Electric Power Company
Table of Contents

Sales to Customers
  Year Ended December 31
(in thousands) 2017 2016 2015
Electric customers – end of year      
Residential 1,009.1
 1,026.0
 1,020.8
Small commercial and industrial 114.5
 116.7
 116.0
Large commercial and industrial 0.7
 0.7
 0.7
Other 2.5
 2.5
 2.6
Total electric customers – end of year 1,126.8
 1,145.9
 1,140.1
       
Steam customers – end of year 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,metals manufacturing, governmental, food products, other manufacturing, health services, mining, retail, and machinery production, as well as to large retail chains.education.

Prior to September 2013, our largest retail electric customers were twoIn February 2015, Tilden, along with another affiliated iron ore minesmine located in the Upper Peninsula of Michigan. The mines were served on an interruptible tariff rate and switched toMichigan, returned as customers after choosing an alternative electric supplier effectivein September 1, 2013. The combinedWe entered into a contract with each of the mines to provide full requirements electric energy salesservice through December 31, 2019. Since 2015, we have been deferring, and expect to the two mines accounted for 3.7% and 6.6% of our total electric utility energy sales during 2013 and 2012, respectively. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition in Item 7.

Effective February 1, 2015, the two mines returned as retail customers. We expectcontinue to defer, the net revenue less cost of sales from thosethe mine sales and will apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceedings. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice.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 Tilden under which it will purchase electric power from UMERC for 20 years for the remaining mine, contingent upon UMERC's construction of natural gas-fired generation in the Upper Peninsula of Michigan. Tilden will continue to receive full requirements electric service from us under the existing contract until UMERC's generation solution in the Upper Peninsula of Michigan begins commercial operation, which is expected to occur in 2019. See Note 4, Related Parties, and Note 21, Regulatory Environment, for more information.

Wholesale Customers:   During 2014, we soldCustomers

We provide wholesale electric powerservice to two ruralvarious customers, including electric cooperatives, and two municipal joint action agencies, located in the states of Wisconsinother investor-owned utilities, municipal utilities, and Michigan. Our wholesale electric energy sales were also made to one other public utility in the region under rates approved by the Federal Energy Regulatory Commission (FERC).marketers. Wholesale sales accounted for approximately 5.7%4.6%, 3.2%, and 3.4% of our total electric energy sales volumes during 2017, 2016, and 3.9%2015, respectively. Wholesale revenues accounted for 3.6%, 2.6%, and 2.9% of total electric operating revenues during 2014, compared with 6.1% of total electric energy sales2017, 2016, and 4.3% of total electric operating revenues during 2013.2015, respectively.

Sales for Resale:   During 2014, theResale

The majority of our sales for resale wereare sold to one Regional Transmission Organization (RTO),into an energy market operated by MISO at market rates based on availability of our generation and RTOmarket demand. Sales for resaleResale sales accounted for approximately 19.9%23.5%, 23.0%, and 23.8% of our total electric energy sales volumes during 2017, 2016, and 7.8%2015, respectively. Resale revenues accounted for 7.1%, 6.5%, and 6.6% of total electric operating revenues during 2014, compared with 13.6%2017, 2016, and 2015, respectively. Retail fuel costs are reduced by the amount that revenue exceeds the costs of total electric energy sales and 4.3% of total electric operating revenues during 2013.

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

Competition

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


11Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2014 Form 10-K

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


2017 Form 10-K5Wisconsin Electric Power Company
Table of Contents

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

below. For more information on our electric generation facilities, see Item 2. Properties.
  Dependable Capability in MW (a)
  2014 2013 2012
Coal 3,707
 3,822
 3,828
Natural Gas - Combined Cycle 1,082
 1,082
 1,090
Natural Gas/Oil - Peaking Units (b) 962
 962
 962
Renewables (c) 155
 155
 107
Natural Gas - Steam Turbine (d) 118
 —
 —
Total 6,024
 6,021
 5,987
  
Rated Capacity in MW (1)
  2017 2016 2015
Coal 3,599
 3,582
 3,589
Natural gas:      
Combined cycle 1,182
 1,140
 1,082
Steam turbine (2)
 240
 240
 240
Natural gas/oil peaking units (3)
 982
 962
 962
Renewables (4)
 191
 190
 187
Total rated capacity 6,194
 6,114
 6,060

(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 VAPP.

(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.

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

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2014, as well as an estimateestimates for 2018:
  Estimate Actual
  2018 2017 2016 2015
Company-owned or leased generation units:        
Coal 47.5% 50.8% 49.9% 53.5%
Natural gas:        
Combined cycle 16.5% 14.7% 15.9% 13.0%
Steam turbine 0.7% 1.1% 1.2% 1.4%
Natural gas/oil peaking units 0.4% 0.5% 0.7% 0.6%
Renewables 3.6% 3.8% 3.5% 3.5%
Total company-owned or leased generation units 68.7% 70.9% 71.2% 72.0%
Power purchase contracts:        
Nuclear 25.5% 25.2% 24.6% 24.5%
Natural gas 3.0% 1.8% 2.4% 1.7%
Renewables 1.7% 1.8% 1.8% 1.1%
Other —% —% —% 0.7%
Total power purchase contracts 30.2% 28.8% 28.8% 28.0%
Purchased power from MISO 1.1% 0.3% —% —%
Total purchased power 31.3% 29.1% 28.8% 28.0%
Total electric utility supply 100.0% 100.0% 100.0% 100.0%

Coal-Fired Generation

Our coal-fired generation, including the ERGS units we lease from We Power, consists of four operating plants with a rated capacity of 3,599 MW as of December 31, 2017. For more information about our operating plants, see Item 2. Properties. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 1,547 MW of coal generation by 2020 with a goal of reducing CO20152: emissions by approximately 40% below 2005 levels by 2030. For more information about future retirement of our plants, see Note 6, Property, Plant, and Equipment.

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


2017 Form 10-K126Wisconsin Electric Power Company
Table of Contents

Natural Gas-Fired Generation

Our natural gas-fired generation, including the PWGS units we lease from We Power, consists of four operating plants, including peaking units, with a rated capacity of 2,204 MW as of December 31, 2017. For more information about our operating plants, see Item 2. Properties.

Oil-Fired Generation

Fuel oil is used for combustion turbines at certain of our natural gas-fired plants as well as for ignition and flame stabilization at one of our coal-fired plants. Our oil-fired generation had a rated capacity of 200 MW as of December 31, 2017. 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

We meet a portion of our electric generation supply with various renewable energy resources. This helps us maintain compliance with renewable energy legislation in Wisconsin and Michigan. These renewable energy resources also help us maintain diversity in our generation portfolio, which effectively serves as a price hedge against future fuel costs, and will help mitigate the risk of potential unknown costs associated with any future carbon restrictions for electric generators. For more information about our renewable generation, see Item 2. Properties.

Hydroelectric

Our hydroelectric generating system consists of 13 operating plants with both a total installed capacity and a rated capacity of 90 MW as of December 31, 2017. All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Wind

We have four wind sites, consisting of 200 turbines, with an installed capacity of 339 MW and a rated capacity of 51 MW as of December 31, 2017.

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 15.8% installed capacity reserve margin requirement for the planning year from June 1, 2017, through May 31, 2018, and a 17.1% installed capacity reserve margin requirement for the planning year from June 1, 2018, through May 31, 2019. MISO's short-term reserve margin requirements experience year-to-year fluctuations, primarily due to changes in the average forced outage rate of generation within the MISO footprint.

ITEM 1. BUSINESS - (Cont'd)20142017 Form 10-K7Wisconsin Electric Power Company
Table of Contents


Michigan recently passed legislation requiring all electric providers to demonstrate to the MPSC that they have enough resources to serve the anticipated needs of their customers for a minimum of four consecutive planning years beginning in the upcoming planning year June 1, 2018, through May 31, 2019. The MPSC has established future planning reserve margin requirements based on the same study conducted by MISO that determines the short-term reserve margin requirements.

In both of our Wisconsin and Michigan jurisdictions, 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 the current and first upcoming planning years. We also fully anticipate that we will have adequate capacity to meet the planning reserve margin requirements for future planning years in both jurisdictions.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.

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 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:
  2014 2013 2012
Coal $27.68
 $27.97
 $30.71
Natural Gas - Combined Cycle $40.64
 $32.22
 $23.62
Natural Gas/Oil - Peaking Units $129.83
 $83.95
 $53.40
Purchased Power $47.47
 $43.74
 $41.92
  2017 2016 2015
Coal $22.26
 $22.68
 $25.25
Natural gas combined cycle 22.85
 19.13
 23.44
Natural gas/oil peaking units 60.44
 46.99
 56.33
Biomass 118.76
 103.24
 168.84
Purchased power 45.50
 43.51
 43.87

Historically,We purchase coal has been purchased under long-term contracts, which helpedhelps with price stability. CoalIn the past, coal and associated transportation services have continuedwere exposed to see volatility in pricing due to changing domestic and world-wide demand for coal and diesel fuel. To moderate the impacts of diesel costs which are incorporated into fuel surcharges on rail transportation.

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

Coal-Fired Generation

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

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

Year Annual Tonnage
  (Thousands)
   
2015 10,843
2016 5,887
2017 3,417

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

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

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


13Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2014 Form 10-K

Natural Gas-Fired Generation

Our natural gas-fired generation consists of five operating plants with a dependable capability of approximately 1,982 MW as of December 31, 2014.2017.

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 also have a PSCW-approved program that allows us to hedge up to 65%75% of our estimated natural gas usageuse for electric generation in order to help manage our natural gas price risk.

Our 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.

Oil-Fired GenerationCoal Supply

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

Renewable Generation

Hydroelectric:   Our hydroelectricour electric generating system consists of 13 operating plants with a total installed capacity of approximately 88 MW and a dependable capability of approximately 39 MW as of December 31, 2014. Of these plants, 12 plants (86 MW of installed capacity) have long-term licensesfacilities by purchasing coal 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 operationseveral mines in November 2013. Wood waste and wood shavings are used to produce a dependable capability of approximately 50 MW of electric powerWyoming, as well as steamfrom various other states. For 2018, approximately 84% of our total projected coal requirements of 8.6 million tons are contracted under fixed-price contracts. See Note 19, 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
2018 7,261
2019 4,536
2020 2,108

2017 Form 10-K8Wisconsin Electric Power Company
Table of Contents


Coal Deliveries

All of our 2018 coal requirements are expected to support Domtar's papermaking operations.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 facility. 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 D. Regulation.

Power Purchase Commitments

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

Year MW (a)
   
2015 1,267
2016 1,267
2017 1,267
2018 1,267
2019 1,267

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

The above commitments include approximately 1,030years are 1,279 MW per year, which exclude planning capacity purchases. 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 tiedagreement for electricity generated by Point Beach. Due to the gas price index.


14Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2014 Form 10-K

Electric Transmissionplanned retirement of generation resources, we have entered into purchase agreements to procure additional planning capacity in order to maintain our compliance with planning reserve requirements as established by the PSCW, MPSC, and Energy MarketsMISO.

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

Seasonality

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 terms and conditions of service and is a transmission-owning member of MISO. MISO maintains operational control of ATC's transmission system, and we are a non-transmission owning member and customer of MISO. We owned approximately 23.0% of ATC as of December 31, 2014 and 2013. For additional information, see Note P -- Related Parties in the Notes to Consolidated Financial Statements.

In April 2011, ATC and Duke Energy announced the creation of a joint venture, Duke-American Transmission Company, that will build, own and operate new electric transmission infrastructure in North America to address increasing demand for affordable, reliable transmission capacity. In April 2013, DATC acquired a 72% interest in California's Path 15 transmission line. DATC continues to evaluate new projects and opportunities, along with participating in the competitive bidding process on projects it considers to be viable. These projects are located in theour service territories, see Item 7. Management's Discussion and Analysis of several different regional transmission organizations around the country.

MISO:   In connection with its status as a FERC approved RTO, MISO developedFinancial Condition and operates the Energy and Operating Reserves Markets, which includes its bid-based energy markets and ancillary services market. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas and Missouri. This new region is referred to as MISO South. We are participants in the West region. These changes have not had a material impact on our allocationResults of MISO costs, and we do not expect them to have a material impact in the future. For further information on MISO and the MISO Energy Markets, 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)2014 Form 10-K

Electric Utility Operating StatisticsRestructuring.

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

SELECTED ELECTRIC UTILITY OPERATING DATA
          
Year Ended December 312014 2013 2012 2011 2010
          
Operating Revenues (Millions)         
Residential$1,199.3
 $1,208.6
 $1,163.9
 $1,159.2
 $1,114.3
Small Commercial/Industrial1,052.9
 1,048.0
 1,013.6
 1,006.9
 922.2
Large Commercial/Industrial637.0
 711.9
 744.3
 763.7
 677.1
Other - Retail23.0
 23.4
 22.8
 22.9
 21.9
Total Retail Revenues2,912.2
 2,991.9
 2,944.6
 2,952.7
 2,735.5
Wholesale - Other131.9
 143.7
 144.4
 154.0
 134.6
Resale - Utilities264.1
 143.2
 53.4
 69.5
 40.4
Other Operating Revenues87.8
 28.4
 51.5
 35.1
 25.8
Total3,396.0
 3,307.2
 3,193.9
 3,211.3
 2,936.3
Electric Customer Choice (a)5.1
 1.5
 —
 —
 —
Total Operating Revenues, including customer choice$3,401.1
 $3,308.7
 $3,193.9
 $3,211.3
 $2,936.3
          
MWh Sales (Thousands)         
Residential7,946.3
 8,141.9
 8,317.7
 8,278.5
 8,426.3
Small Commercial/Industrial8,805.1
 8,860.4
 8,860.0
 8,795.8
 8,823.3
Large Commercial/Industrial7,393.3
 8,673.4
 9,710.7
 9,992.2
 9,961.5
Other - Retail148.7
 152.3
 154.8
 153.6
 155.3
Total Retail Sales24,293.4
 25,828.0
 27,043.2
 27,220.1
 27,366.4
Wholesale - Other1,852.8
 1,953.5
 1,566.6
 2,024.8
 2,004.6
Resale - Utilities6,497.9
 4,382.7
 1,642.4
 2,065.7
 1,103.8
Total Electric Sales32,644.1
 32,164.2
 30,252.2
 31,310.6
 30,474.8
Electric Customer Choice (a)2,440.0
 813.0
 —
 —
 —
Total MWh Delivered35,084.1
 32,977.2
 30,252.2
 31,310.6
 30,474.8
          
Customers - End of Year (Thousands)         
Residential1,015.0
 1,010.5
 1,008.2
 1,005.5
 1,003.6
Small Commercial/Industrial115.4
 114.6
 114.3
 113.8
 113.5
Large Commercial/Industrial0.7
 0.7
 0.7
 0.7
 0.7
Other2.5
 2.5
 2.5
 2.5
 2.4
Total Customers1,133.6
 1,128.3
 1,125.7
 1,122.5
 1,120.2
          
Customers - Average (Thousands)1,130.6
 1,126.9
 1,123.8
 1,121.0
 1,118.7
          
Degree Days (b)         
Heating (6,601 Normal)7,616
 7,233
 5,704
 6,633
 6,183
Cooling (732 Normal)464
 688
 1,041
 793
 944
For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 19, 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)2014 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.


2017 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
  2017 2016 2015
Operating revenues (in millions)
      
Residential $249.0
 $238.6
 $256.6
Commercial and industrial 114.3
 105.0
 118.9
Total retail revenues 363.3
 343.6
 375.5
Transport 13.7
 13.6
 16.0
Other operating revenues * (1.5) (5.0) 8.2
Total $375.5
 $352.2
 $399.7
       
Customers – end of year (in thousands)
      
Residential 445.9
 442.0
 438.7
Commercial and industrial 39.6
 39.4
 39.1
Transport 0.8
 0.7
 0.7
Total customers 486.3
 482.1
 478.5

*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 983.5 million therms during 2014, a 6.4% increase compared with 2013. As of December 31, 2014, we were transporting gas for approximately 580 customers who purchased gas directly from other suppliers.natural gas. Transported natural gas accounted for approximately 34.9%36.9% of the total volumes delivered during 2014, 35.4%2017, 38.0% during 20132016, and 42.6%36.4% during 2012. We had approximately 475,100 and 471,300 gas customers as of December 31, 2014 and 2013, respectively.2015. Our peak daily send-out during 20142017 was 852,086 Dth6.8 million therms on January 6, 2014.December 27, 2017.

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 governmental, education, restaurants, paper mills, and food products, chemicals and fabricated metal products.

Natural Gas Deliveries Growth:   We currently forecast total retail thermSales Forecast

Our service territory experienced growth in weather-normalized natural gas deliveries (excluding natural gas deliveries for electric generation) in 2017 due to positive customer growth, an improving economy, and favorable natural gas prices. We currently forecast retail natural gas delivery volumes to grow at a compound annual rate ofbetween flat and 0.5% over the five-year period ending December 31, 2019. Thisnext five years, assuming normal weather. The forecast reflects a current year weather normalized sales level and normal weather.projects declining average usage per customer partially offsetting positive customer growth.

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 19, 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)2014 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 33%40% of forecasted winter demand; November through March is considered the winter season. Storage capacity, along with our natural gas purchase contracts, enables us to manage significant changes in daily demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months when demand is lower and withdraw it in the winter months.

2017 Form 10-K10Wisconsin Electric Power Company
Table of Contents

As a result, we can contract for less long-line pipeline capacity during periods of peak usage than would otherwise be necessary and can purchase natural gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.

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

To ensure a reliable supply of natural gas during peak winter conditions, we have liquefied natural gas and propane facilities located within our distribution system. These facilities are typically utilized during extreme demand conditions to ensure reliable supply to our customers.

In June 2017, our parent company completed the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that will provide a portion of the current storage needs for our natural gas utility operations. We have entered into a long-term service agreement to take the allocated storage. 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 10.2 million therms for the 2017 through 2018 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 peaknear-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 2014,2017, 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 opportunity 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, brokerage fees and brokerage fees)losses) and proceeds (gains and losses)(gains) 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.

2017 Form 10-K1811Wisconsin Electric Power Company
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Our working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of our winter natural gas supply needs is typically purchased and 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 are 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 success of third-party natural gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating competitively priced transportation service for those customers that desire to buy their own natural gas supplies.

Federal and state regulators continue to implement policies to bring more competition to the natural gas industry. While the natural gas utility distribution function is expected to remain a highly regulated, monopoly function, the sale of the natural gas commodity and related services are expected to remain subject to competition from third parties for large commercial and industrial customers.

C. OTHER SEGMENT

Our other segment includes Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. See Note 3, Dispositions, for more information. Bostco no longer has significant operations.

Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information.

D. REGULATION

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 the United States Army Corps of Engineers.

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.
ITEM 1. BUSINESS - (Cont'd)Regulated Rates2014 Form 10-KRegulatory Commission
Retail electric, natural gas, and steamPSCW
Retail electricMPSC *
Wholesale powerFERC

Gas Utility Operating Statistics

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

SELECTED GAS UTILITY OPERATING DATA
           
Year Ended December 31 2014 2013 2012 2011 2010
           
Operating Revenues (Millions)          
Residential $390.5
 $296.0
 $250.7
 $304.1
 $310.6
Commercial/Industrial 201.6
 138.4
 115.4
 149.9
 151.3
Interruptible 2.9
 2.4
 2.3
 2.8
 3.1
Total Retail Gas Sales 595.0
 436.8
 368.4
 456.8
 465.0
Transported Gas 16.8
 16.0
 15.1
 15.0
 14.2
Other Operating Revenues 2.4
 (0.9) 1.6
 5.5
 2.4
Total Operating Revenues $614.2
 $451.9
 $385.1
 $477.3
 $481.6
           
Therms Delivered (Millions)          
Residential 399.3
 380.8
 294.3
 339.4
 321.8
Commercial/Industrial 236.2
 210.9
 165.3
 198.7
 184.5
Interruptible 4.9
 5.4
 5.0
 5.3
 5.5
Total Retail Gas Sales 640.4
 597.1
 464.6
 543.4
 511.8
Transported Gas 343.1
 327.6
 344.5
 294.4
 300.8
Total Therms Delivered 983.5
 924.7
 809.1
 837.8
 812.6
           
Customers - End of Year (Thousands)          
Residential 435.6
 432.1
 429.6
 427.1
 425.6
Commercial/Industrial 38.9
 38.6
 38.5
 38.5
 38.3
Transported Gas 0.6
 0.6
 0.5
 0.4
 0.4
Total Customers 475.1
 471.3
 468.6
 466.0
 464.3
           
Customers - Average (Thousands) 472.6
 469.7
 466.9
 464.7
 462.9
           
Degree Days (a)          
Heating (6,601 Normal) 7,616
 7,233
 5,704
 6,633
 6,183

(a)*As measured at Mitchell International AirportEffective January 1, 2017, we transferred all of our electric distribution assets and customers located in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden. See Note 4, Related Parties, and Note 21, Regulatory Environment, for more information.


STEAM UTILITY OPERATIONS

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

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

2017 Form 10-K1912Wisconsin Electric Power Company
Table of Contents

Embedded within our electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of our symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of our approved fuel and purchased power cost plan. Our deferred fuel and purchased power costs are subject to an excess revenues test. If our ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which our return exceeds the authorized amount. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customer and our 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 21, 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:
  2017 2016 2015
(in millions) Amount Percent Amount Percent Amount Percent
Electric            
Wisconsin $2,901.2
 87.0% $2,973.3
 86.4% $2,961.9
 85.7%
Michigan * 78.2
 2.3% 154.2
 4.5% 163.0
 4.7%
FERC – Wholesale * 356.8
 10.7% 313.1
 9.1% 329.5
 9.6%
Total 3,336.2
 100.0% 3,440.6

100.0% 3,454.4
 100.0%
             
Natural Gas – Wisconsin 375.5
 100.0% 352.2
 100.0% 399.7
 100.0%
             
Total utility operating revenues $3,711.7
 

 $3,792.8
 

 $3,854.1
 


*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 Tilden. UMERC currently purchases a portion of its power from us. The revenues received from UMERC are primarily included in the FERC - Wholesale line above. See Note 4, Related Parties, and Note 21, Regulatory Environment, for additional information on UMERC.

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 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 currently being paid by load-serving entities located in the service territories of each MISO transmission owner. The FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.


ITEM 1. BUSINESS - (Cont'd)20142017 Form 10-K13Wisconsin Electric Power Company


Table of Contents
UTILITY RATE MATTERS

See Factors Affecting Results, LiquidityAs part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and Capital Resources -- Ratesmid-Atlantic states. The LMP system includes the ability to hedge transmission congestion costs through ARRs and Regulatory Matters in Item 7.FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2017, through May 31, 2018. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.


REGULATIONMISO has 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 can be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. Our capacity requirements during the 2017 planning year were fulfilled using our own capacity resources.

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

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

We are subject to the regulation of the PSCW as to retail electric, gasAct 141 in Wisconsin and steam rates in the state of Wisconsin, standards of service, issuance of securities, construction of certain new facilities, transactions with affiliates, billing practicesPublic Acts 295 and various other matters. We are also subject to the regulation of the PSCW as to certain levels of short-term debt obligations. We are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state of Michigan, except as to the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Almost all of our hydroelectric facilities are regulated by FERC. We are subject to the regulation of FERC with respect to wholesale power service, electric reliability requirements and accounting and with respect to our participation in the interstate natural gas pipeline capacity market. For information on how rates are set, see Rates and Regulatory Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7.

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

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

100.0% 3,193.9
 100.0%
             
Gas - Wisconsin - Retail 614.2
 100.0% 451.9
 100.0% 385.1
 100.0%
             
Steam - Wisconsin - Retail 44.1
 100.0% 39.6
 100.0% 34.3
 100.0%
Total Utility Operating Revenues $4,059.4
 

 $3,800.2
 

 $3,613.3
 


For additional information on our business operations342 in Michigan, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition - Michigan Business in Item 7.

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


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

Public Benefits and Renewable Portfolio Standard

2005 Wisconsin Act 141 (Act 141) established a goal that 10% of electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we must meetwhich contain certain minimum requirements for renewable energy generation. ForSee Note 19, Commitments and Contingencies, for more information.

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

Other Natural Gas Regulations

Almost all of the years 2010 through 2014,natural gas we weredistribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the PSCW are responsible for monitoring and enforcing requirements governing our natural gas safety 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 Other Gas by Pipeline; Annual Reports, Incident Reports, and 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).

We are required to increaseprovide natural gas service and grant credit (with applicable deposit requirements) to customers within our percentageservice 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 a limited amount of total retail energy sales provided by renewable sources (renewable energy percentage) by at least two percentage points fromfunding for assistance to our baseline renewable percentage of 2.27%. As of December 31, 2014, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. We expect to be in compliance with this standard. In addition, under this Act, 1.2% of utilities' annual operating revenues were required to be used to fund energy conservation programs in 2014. The funding required by Act 141 for 2015 is also 1.2% of annual operating revenues.low-income customers.

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 --19, 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 $1.0 million in 2014 compared with $24.7 million in 2013. Expenditures incurred during 2014 and 2013 primarily included costs associated with the installation of pollution abatement facilities at our power plants. No future expenditures are currently anticipated. Operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $110.3 million and $92.9 million during 2014 and 2013, respectively.

Coal Combustion Product Fills and Landfills

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


2017 Form 10-K2114Wisconsin Electric Power Company
ITEM 1. BUSINESS - (Cont'd)2014 Form 10-K

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


OTHERF. EMPLOYEES

Research and Development:   WeAs of December 31, 2017, 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.2,945 employees.

Employees:As of December 31, 2014,2017, we had 3,823 total employees of which 2,492 were represented under labor agreements with the following bargaining units:

  Number of Employees Expiration Date of Current Labor Agreement
Local 2150 of International Brotherhood of Electrical Workers, AFL-CIO 1,7281,627
 August 15, 20172020
Local 420 of International Union of Operating Engineers, AFL-CIO 524443
 September 30, 20172021
Local 2006 Unit 1 of United Steel Workers of America, AFL-CIO 133124
 April 30, 2017October 31, 2021
Local 510 of International Brotherhood of Electrical Workers, AFL-CIO 10789
 October 31, 20162020
Total 2,4922,283
  



2017 Form 10-K2215Wisconsin Electric Power Company
Table of Contents
2014 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. These regulations significantly influence our operating environment, may affect our ability to recover costs from utility customers, and cause us to incur substantial compliance costs. Changes in regulations, interpretations of regulations, or the imposition of new regulations could also significantly impact us, including requiring us to change our business operations. Many aspects of our operations are regulated and impacted by government regulation, including, but not limited to: the rates we charge our retail electric, natural gas, and steam customers; our authorized rates inof return; construction and operation of electric generating facilities and electric and natural gas distribution systems and the stateability to recover such costs; decommissioning generating facilities and the ability to recover the related costs and continuing to recover the return on the carrying value 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 ourthese facilities; wholesale power service practices,practices; electric reliability requirements and accounting, andaccounting; participation in the interstate natural gas pipeline capacity market. Our significant levelmarket; standards of regulation imposes restrictions on our operationsservice; issuance of securities; short-term debt obligations; transactions with affiliates; 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 failedbilling practices. 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 85% of our 2014 electric revenues were regulated by the PSCW, 2% were regulated by the MPSC and the balance of our electric revenues were regulated by the FERC. All of our natural gas and steam revenues are regulated by the PSCW. Rate regulation is based on providingprovides us 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.

Also,If we are unable to recover costs of complying with regulations or other associated costs in customer rates in a timely manner, or if 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)2014 Form 10-K

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

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

We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. For example, we are in the process of converting the fuel source for VAPP from coal to natural gas. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC. These and other compliance costs we expect to incur over the next three years are included in the table under "Capital Expenditures" in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations.

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

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.


2017 Form 10-K16Wisconsin Electric Power Company
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The EPA adopted and implemented (or is in the process of implementing) regulations governing the emission of NOx, SO2, fine particulate matter, mercury, and other air pollutants under the Clean Air Act through the NAAQS, the Mercury and Air Toxics Standards rule, the CPP, the CSAPR, and other air quality regulations. In addition, the EPA finalized regulations under the Clean Water Act that govern cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA and the United States Army Corps of Engineers (Army Corps) have 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, and the EPA and the Army Corps have proposed rescinding it. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. In addition, as a result of the new Federal Executive Administration taking office in January 2017 and the actions it has taken to date, as well as 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 could result in significant additional expenditures for our generation units or distribution systems, including, without limitation, costs to further limit GHG emissions from our operations; operating restrictions on our facilities; and increased compliance costs. In addition, the operation of emission control equipment and compliance with rules regulating our intake and discharge of water could increase our operating costs and reduce the generating capacity of our power plants. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels.

As a result, certain of our coal-fired electric generating facilities may become uneconomical to maintain and operate, which could result in some of these units being retired or converted to an alternative type of fuel. For example, we expect to retire 1,547 MW of coal generation by 2020, including Pleasant Prairie power plant and PIPP. If other generation facility owners in the Midwest 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, 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, the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, a change in conditions or discovery of additional contamination, 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 electric and gas utility businesses are also subject to significant liabilities related to the investigation and remediation of environmental contamination at certain of our current and former facilities, and at third-party owned sites. Due to the potential for imposition of stricter standards and greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate.

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

24Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2014 Form 10-K

by coal combustion residualsenvironmental impacts and alleged exposure to hazardous materials have become more frequent. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of 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.

Federal, state, regional, and international authorities have undertaken efforts to limit greenhouse gas (GHG)GHG emissions. The regulation of GHG emissions continues to be a top priority for the President's administration.
The EPA is pursuing regulation of GHG emissions under the CAA. The EPA issued new rules with GHG limits for new fossil fueled power plants that became effective in June 2014. The rule does not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines.

With respect to existing generating units,In 2015, the EPA issued a proposed rule in June 2014, and is expected to issue a final rule by mid-summer 2015. Theregulating GHG emissions from existing generating units, referred to as the CPP, a proposed rule would require statesfederal plan and model trading rules as alternatives or guides to submit state compliance plans, as early as June 30, 2016. Single states requesting a one year extension would be required to submit state plans by June 30,and final performance standards for modified and reconstructed generating units

2017 Form 10-K17Wisconsin Electric Power Company
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and new fossil-fueled power plants. With the January 2017 change in the Federal Executive Administration, the legal and states that are partregulatory future of a multi-state plan that request a two year extension would be required to submit state plans by June 30, 2018.federal GHG regulations, including the CPP, faces increased uncertainty. We are incontinuing to analyze the processGHG emission profile of reviewing the proposed ruleour electric generation resources and to work with other stakeholders to determine the potential impacts to our operations. We expect that theseoperations of the CPP, any successor rule, and federal GHG regulations as currently proposed would impact how we operate our existing facilities, particularly our fossil fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.in general.

Legislation to regulate GHG emissions and establish renewable and efficiency standards has also been considered on the state level. BothIn October 2015, numerous states (including Wisconsin and Michigan have adopted renewable portfolio standardsMichigan) and energy optimization (efficiency) targets.other 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 CPP 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. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In October 2017, the EPA issued a proposed rulemaking to repeal the CPP. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan to implement the CPP.

There is no guarantee that we will be allowed to fully recover costs incurred to comply with the impendingCPP or other federal regulations, that will require a reduction in GHG emissions or that cost recovery will not be delayed or otherwise conditioned. TheseThe CPP and any other related regulations that may be adopted in the future, at either the federal or state level, may cause our environmental compliance spending over the next several years to differ materially from the amounts currently estimated. Any legislation or regulation that may ultimately be adopted, either atIn December 2016, Michigan enacted Act 342, which retains the federal or state level, designed10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement to reduce GHG emissions could have a material adverse impact on our electric generation12.5% 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, may impact how we operate our existing fossil-fueled power plants and biomass facility, and could affect unit retirement and replacement decisions.decisions in the future. These regulations could also adversely affect our future results of operations, cash flows, and possiblyfinancial 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 also continue to monitor efforts by investors and other stakeholders to increase pressure on us and others to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius. These efforts could impact how we operate our electric generating units and natural gas facilities and lead to increased competition and regulation, all of which could have a material adverse effect on our operations and financial condition.

Recent changes in federal income tax policy may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings.

Recently enacted United States federal income tax legislation significantly changed the United States Internal Revenue Code, including taxation of United States corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Tax Legislation is unclear in certain respects and will require interpretations and implementing regulations by the Treasury Department and the IRS, as well as state income tax authorities, and the Tax Legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain adverse impacts of the Tax Legislation. In addition, the regulatory treatment of the impacts of the Tax Legislation will be subject to the discretion of the FERC and state public utility commissions. State and local taxing authorities are in the early stages

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of evaluating the impact of federal income tax reform, and any changes on the state or local level could lessen or increase the impacts of the Tax Legislation.

Although it is unclear when or how capital markets, credit rating agencies, the FERC, or state public utility commissions may ultimately respond to the Tax Legislation, we do expect that certain financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, could be negatively impacted as a result of certain limitations on tax deductions. It is uncertain how credit rating agencies will treat the impacts of the Tax Legislation on their credit ratings and metrics, and whether additional opportunities will evolve for companies to manage the adverse aspects of the Tax Legislation, including the impacts on certain credit metrics.

In addition, the FERC and state public utility commissions have started to engage with us to determine how any tax savings will be returned to customers. We expect that we will return the tax benefits to our customers through refunds, bill credits, or reductions in regulatory assets. The amount of tax benefits to be returned to customers will ultimately be determined by our regulators. If the amounts our regulators order us to return to customers exceeds the actual amount of tax savings realized, or our regulators require the tax savings to be applied in a manner other than we had expected, it could have a material adverse effect on our financial condition, results of operations, and cash flow.

While our analysis and interpretation of the Tax Legislation is preliminary and ongoing, based on our current evaluation, we do not expect the limitations on interest deductions to materially adversely affect our earnings. Any amendments to the Tax Legislation or interpretations or implementing regulations by the Treasury Department and/or the IRS contrary to our interpretation of the Tax Legislation could limit our ability to deduct the interest on some of our outstanding debt.

There may be other material adverse effects resulting from the Tax Legislation that we have not yet identified. If we are unable to successfully take actions to manage any adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the Tax Legislation could have an adverse effect on our financial condition, results of operations, cash flows, and on the value of investments in our debt securities, and could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us to issue future debt securities and certain other types of financing and could increase borrowing costs under our credit facility.

Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material effect on our results of operations.

We are subject to reporting, disclosure control, and other obligations under Section 404 of the Sarbanes-Oxley Act (SOX). SOX contains provisions requiring our management to report on the effectiveness of our internal control over financial reporting. We have undertaken, or will undertake, a variety of initiatives to integrate, standardize, centralize, and streamline our operations with technology, including, but not recovered through regulated rates.limited to, an enterprise resource planning system and a customer information and billing system. There is a risk that we will not be able to conclude that our internal control over financial reporting is effective because of the discovery of material weaknesses, with either our current controls and processes or with the implementation of new controls and processes around these new technologies. Any failure to maintain effective internal controls could cause investors to lose confidence in the accuracy or completeness of our financial reports, restrict our access to the capital markets, or subject us to investigations by the SEC or other regulatory authorities.

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

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

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

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

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

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

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 distribution, as well as ournatural 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 environmental or other regulatory requirements; terrorist attacks; or cyber security threats; or catastrophicintrusions. Any of these events such as fires, earthquakes, explosions, floods, droughts, pandemic healthcould 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 such as influenzas or other similar occurrences.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 and natural gas has decreased as a result of continued individual conservation efforts, including the use of more energy efficient technologies. 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. For example, several states, including Wisconsin and Michigan, 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.

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.

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, and electric generating facilities. We expect to spend an aggregateother projects, including projects for environmental compliance. Achieving the intended benefits of between $2.3 billion and $2.5 billion during the period 2015 to 2019 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

2017 Form 10-K20Wisconsin Electric Power Company
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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 in rates.


26Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2014 Form 10-K

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

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

In the event we experience any of these weather events or other natural disaster,disallow recovery of anythem through rates. To the extent that delays occur, costs in excess of any reservesbecome unrecoverable, or applicable insurance is subjectwe otherwise become unable 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 affecteffectively manage and complete our capital 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.

We could be theOur operations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of cyber intrusions that disrupt our electric generation and gas distribution operations and/war, or result in security breaches that expose usunauthorized access to a risk of loss or misuse of confidential and proprietary information, litigation and potential liability.personally identifiable information.

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

We operate in an industry that requires the continued operation of sophisticated information technology systems and network infrastructure, which are part of an interconnected regional transmission grid. In addition, in the ordinary course of business, we collect and retain sensitive information including personal identification information about our customers and employees and other confidential information. We face on-going threats to our assets and technology systems. Despite the implementation of strong security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to human error, orterrorist attacks, and physical or cyber attacks.security intrusions. These threats against our generation facilities, electric and natural gas distribution infrastructure, our information and technology systems, and network infrastructure, including that of third parties on which we rely, could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. 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.

CyberWe 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 for the electric and natural gas transmission and distribution systems, could disrupt our operations and result in a full or partial disruption of our electric generation and/or gas distribution operations. Any disruption of these operations could result in a loss of service to customers and acustomers. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant decrease in revenues, as well as significant expensecosts if we are required to repair system damage and remedy security breaches. Furthermore, we may need to obtain more expensive purchasedoperate our higher cost electric generators or purchase replacement power to meet customer demand for electricity ifsatisfy our electric generating facilities are unable to operate at full capacityobligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of a cyber intrusion. Any resulting losshaving to implement increased security measures for protection of revenue or increase in expense could have a material adverse effect on our results of operations, cash flowinformation technology and financial condition.infrastructure.

Our continued efforts to integrate, consolidate, and streamline our operations have also resulted in increased reliance on current and recently completed projects for technology systems, including an enterprise resource planning system, a customer information and billing system, automated meter reading systems, and other similar technological tools and initiatives. We implement procedures to protect our systems, but we cannot guarantee that the procedures we have implemented to protect against unauthorized access to secured data and systems are adequate to safeguard against all security breaches. The failure of any of these or other similarly important technologies, or our inability to support, update, expand, and/or integrate these technologies with those of our affiliates could materially and adversely impact our operations, diminish customer confidence and our reputation, materially increase the costs we incur to protect against these risks, and subject us to possible financial liability or increased regulation or litigation.

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

2017 Form 10-K2721Wisconsin Electric Power Company
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ITEM 1A. RISK FACTORS - (Cont'd)2014 Form 10-K


In addition, any theft, losslarge costs to notify and protect the impacted persons, and/or fraudulent use of customer, stockholder, employee or proprietary data as a result of cyber intrusion or otherwise could cause us to become subject us to significant litigation, costs, liability, fines, or penalties, any of which could materially and costs,adversely impact our results of operations as well as adversely impact our reputation with customers stockholders and regulators, among others.

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

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

Our electric generation and gas distribution facilities, including the facilities of third parties on which we rely, could be targets of terrorist activities. A terrorist attack on our facilities (or those of third parties) could result in a full or partial disruption of our ability to generate, transmit, transport, purchase or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions caused by these on-going threats to our assets and technology systems 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. The costs of repairing damage to our facilities, operational disruptions, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may also not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.

FailureTransporting 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 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 7.8% of our electric revenues. Revenues are dependent on the continued performance by the purchasers of their obligations under the power purchase agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more purchasers could fail to perform their obligations under the power purchase agreements. If this were to occur, we would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase agreement would be reallocated among our retail customers.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.

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

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


2017 Form 10-K2822Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2014 Form 10-K

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

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

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

Risks Related to Economic and Market Volatility

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

We rely on access to short-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, thewar; and
The overall health and view of the utility and financial institution industries, a negative viewindustries.

If any of these risks or uncertainties limit our access to the utility industry, bankruptcycredit and capital markets or financial distress at a financial institution or sovereign entity or other factors,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.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 us or the utility industry or us has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings. If we are downgraded

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.


See the risk factor titled "Recent changes in federal income tax policy may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings" above for information about how the Tax Legislation could impact our credit ratings.
29Wisconsin Electric Power Company

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

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. In addition,gas, and the availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and costaccessibility.


2017 Form 10-K23Wisconsin Electric Power Company
Table of natural gas. Higher natural gas costs can have the effect of increasing demand for other sources of fuel thereby increasing the costs of those fuels as well. Additionally, high natural gas costs increase our working capital requirements and could adversely impact our collection of accounts receivable.Contents

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. OurPrudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our wholesale electric customers. We receive dollar-for-dollar recovery of prudently incurred natural gas distribution business receives dollarcosts from our natural gas customers.

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 dollar recoveryenergy, 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.

We are dependent on coal for much of ourown and operate several coal-fired electric generating capacity.units. 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 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 additionalwhich could lead to increased fuel costs. The increase in fuel costs could result from either reduced margins on net sales into the MISO Energy Markets, a reduction in the volume of net sales into the MISO Energy Markets, and/or an increase in net 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 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. If we are unable to run our lower cost units we may lose the ability to engage in these opportunity sales, which may adversely affect our results of operations.

The use of derivative contracts could result in financial losses.

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

Restructuring in the regulated energy industry and competition in the retail and wholesale markets could have a negative impact on our business.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. It is uncertain whether retail access might be implemented in Wisconsin.


30Wisconsin Electric Power Company
ITEM 1A. RISK FACTORS - (Cont'd)2014 Form 10-K

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

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 allAll market participants, including us, must submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes a Locational Marginal Price (LMP)an LMP that reflects the market price for energy. As a participant in the MISO Energy Markets, weWe are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining the stability of the transmission system. MISO also implemented an Ancillary Services Marketancillary services market for operating reserves that was simultaneously co-optimized with its existingschedules energy markets.

and ancillary services at the same time as part of the energy market, allowing for more efficient use of generation assets in the MISO Energy Markets. These market designs continue to have the potential to

2017 Form 10-K24Wisconsin Electric Power Company
Table of Contents

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

PoorThe 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 impacting benefit plan costs could unfavorably impact our liquidity and results of operations.market conditions.

We have significant obligations related to pension and other post-retirementOPEB plans. If WEC Energy Group is unable to successfully manage our benefit plans.plan assets and medical costs, our cash flows, financial condition, or results of operations could be adversely impacted. Our cost of providing these 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. In addition, it is possible that medical costs for both active orand retired employees may increase at a rate that is significantly higher than we currently anticipate. If we are unable to successfully manage our benefitOur 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.



2017 Form 10-K3125Wisconsin Electric Power Company
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2014 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, 2014,2017, we owned, or leased from We Power, the following generating assets:

    No. of Dependable
    Generating Capability
Name Fuel Units In MW (a)
Coal-Fired Plants      
South Oak Creek Coal 4
 993
Oak Creek Expansion Coal 2
 1,057
Presque Isle Coal 5
 344
Pleasant Prairie Coal 2
 1,188
Valley Power Plant Coal 1
 118
Milwaukee County Coal 3
 7
Total Coal-Fired Plants   17
 3,707
Natural Gas-Fired Plants      
Valley Power Plant Gas 1
 118
Port Washington Generating Station Gas 2
 1,082
Germantown Combustion Turbines Gas/Oil 5
 258
Concord Combustion Turbines Gas/Oil 4
 352
Paris Combustion Turbines Gas/Oil 4
 352
Other Combustion Turbines & Diesel Gas/Oil 2
 —
Total Natural Gas-Fired Plants   18
 2,162
Renewables      
Hydro Plants (13 in number)   33
 39
Rothschild Biomass Plant Biomass 1
 50
Byron Wind Turbines Wind 2
 —
Blue Sky Green Field Wind 88
 29
Glacier Hills Wind 90
 32
Montfort Wind Energy Center Wind 20
 5
Total Renewables   234
 155
Total System   269
 6,024
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
 359
(3) 
OCPP Oak Creek, WI Coal 4
 995
 
Total coal-fired plants     13
 3,599
 
Natural gas-fired plants         
Concord Combustion Turbines Watertown, WI Natural Gas/Oil 4
 352
 
Germantown Combustion Turbines Germantown, WI Natural Gas/Oil 5
 278
 
Paris Combustion Turbines Union Grove, WI Natural Gas/Oil 4
 352
 
PWGS Port Washington, WI Natural Gas 2
 1,182
 
VAPP Milwaukee, WI Natural Gas 2
 240
 
Total natural gas-fired plants     17
 2,404
 
Renewables         
Hydro Plants (13 in number) WI and MI Hydro 30
 90
 
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
 191
 
Total system     261
 6,194
 

(a)
(1)
Dependable capabilityBased on expected capacity ratings for summer 2018, 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 two other unaffiliated entities. 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 aits 83.34% ownership.

(3)
We have announced plans for retirement of Pleasant Prairie power plant and PIPP. The Pleasant Prairie power plant is scheduled to be shut down in April 2018; therefore, rated capacity factor of approximately 20%.on that plant is based on capacity ratings for summer 2017. See Note 6, Property, Plant, and Equipment, for more information on the plant retirements.

As of December 31, 2014,2017, we operated approximately 21,457 pole-miles19,800 miles of overhead distribution lines and 24,30324,600 miles of underground distribution cable, as well as approximately 350310 electric distribution substations and 295,461approximately 287,200 line transformers.

As of December 31, 2014,2017, our natural gas distribution system included approximately 9,74011,100 miles of distribution mains connected at 2725 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 412,000 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.


2017 Form 10-K3226Wisconsin Electric Power Company
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ITEM 2. PROPERTIES - (Cont'd)2014 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 services occupy private property, we have in some, but not all instances, obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.

As of December 31, 2014,2017, 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.


ITEM 3.LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS

In addition to those legal proceedings discussed below,in Note 19, Commitments and Contingencies, and Note 21, Regulatory Environment, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these other legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

ENVIRONMENTAL MATTERS

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

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

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

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


UTILITY RATE MATTERS

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

OTHER MATTERS

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


33Wisconsin Electric Power Company
2014 Form 10-K

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

Not Applicable.


2017 Form 10-K27Wisconsin Electric Power Company
Table of Contents

EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, at December 31, 2014 and positions of our executive officers at December 31, 2017 are listed below along with their business experience during the past five years. All officers are appointed until they resign, die, or are removed pursuant to theour Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.

Gale E. Klappa.   Age 64.
Wisconsin Energy -- Chairman of the Board and Chief Executive Officer since May 2004. President from April 2003 to July 2013.
Wisconsin Electric -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
Wisconsin Gas -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
Director of Joy Global, Inc. and Badger Meter, Inc.
Director of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas since 2003.

Stephen P. Dickson.   Age 54.
Wisconsin Energy -- Vice President since 2005. Controller since 2000.
Wisconsin Electric -- Vice President since 2005. Controller since 2000.
Wisconsin Gas -- Vice President since 2005. Controller since 1998.

J. Kevin Fletcher.   Age 56.
Wisconsin Electric -- Senior Vice President since October 2011.
Wisconsin Gas -- Senior Vice President since October 2011.
Georgia Power -- Vice President - Community and Economic Development from 2007 to October 2011. Georgia Power is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.

Robert M. Garvin.   Age 48.
Wisconsin Energy -- Senior Vice President since April 2011.
Wisconsin Electric -- Senior Vice President since April 2011.
Wisconsin Gas -- Senior Vice President since April 2011.
American Transmission Co. -- Vice President and General Counsel from 2009 to April 2011.

J. Patrick Keyes.   Age 49.
Wisconsin Energy -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
Wisconsin Electric -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
Wisconsin Gas -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
Accenture -- Senior Executive from September 2001 to March 2011.

Allen L. Leverett. (1)Age 48.51.
WisconsinWEC Energy --Group — President since August 2013. Chief Executive Officer from May 2016 to October 2017. Director since January 2016. 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 from May 2016 to December 31, 2017. Director from June 2015 to January 2018. 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 59.
34Wisconsin Electric Power Company
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.
EXECUTIVE OFFICERS OF THE REGISTRANT - (Cont'd)2014 Form 10-K

Robert M. Garvin.   Age 51.
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 48.
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.

Margaret C. Kelsey. (2)   Age 53.
WEC Energy Group — Executive Vice President since September 2017.
Modine Manufacturing Company — General Counsel, Corporate Secretary, and Vice President - Legal from April 2008 to August 2017. Vice President - Corporate Communications from April 2014 to August 2017.

Scott J. Lauber.   Age 52.
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. (2)Age 62.65.
WisconsinWEC Energy --Group — Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.
Wisconsin Electric -- Executive Vice President and General 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. (3)Age 50.
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 52.
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.

2017 Form 10-K28Wisconsin Electric Power Company
Table of Contents


Joan M. Shafer. (4)Age 64.
WE — Executive Vice President - Human Resources and Organizational Effectiveness since June 2015. Senior Vice President - Customer Services from January 2012 to June 2015.

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.

(1)
On October 12, 2017, we filed a Form 8-K to disclose that Mr. Leverett had suffered a stroke. The Board of Directors of WEC Energy Group appointed Gale E. Klappa to act as Chief Executive Officer of WEC Energy Group until such time as Mr. Leverett is able to resume those responsibilities. Mr. Klappa then became Chairman of the Board and Chief Executive Officer of WE effective January 1, 2018. Mr. Klappa was also appointed to the WE Board of Directors effective January 1, 2018.

(2)
In July 2017, we announced Ms. Martin's intent to retire in early 2018. As part of that transition, effective January 1, 2018, Ms. Kelsey was appointed Executive Vice President, General Counsel, and Corporate Secretary of WEC Energy Group and WE, and Ms. Martin was appointed Executive Vice President of WEC Energy Group and WE. Also effective January 1, 2018, Ms. Kelsey became a Director of WE and Ms. Martin resigned as a Director of WE.

(3)
Mr. Metcalfe was elected to the WE Board of Directors effective January 15, 2018.

(4)
Ms. Shafer announced that she will be retiring effective May 1, 2018.


2017 Form 10-K29Wisconsin Electric Power Company
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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.shareholder, WEC Energy Group. There is no established public trading market for our common stock.

Quarter 2014 2013    
 (Millions of Dollars)
    
(in millions) 2017 2016
First $110.0
 $60.0
 $60.0
 $160.0
Second 110.0
 110.0
 60.0
 60.0
Third 110.0
 60.0
 60.0
 100.0
Fourth 60.0
 110.0
 60.0
 135.0
Total $390.0
 $340.0
 $240.0
 $455.0

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 8, 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.



2017 Form 10-K3530Wisconsin Electric Power Company
Table of Contents
2014 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 2014 2013 2012 2011 2010
Year Ended December 31          
Earnings available for
     common stockholder (Millions)
 $376.7
 $360.0
 $366.1
 $338.4
 $314.2
           
Operating Revenues (Millions)          
Electric $3,401.1
 $3,308.7
 $3,193.9
 $3,211.3
 $2,936.3
Gas 614.2
 451.9
 385.1
 477.3
 481.6
Steam 44.1
 39.6
 34.3
 39.0
 38.8
Total operating revenues $4,059.4
 $3,800.2
 $3,613.3
 $3,727.6
 $3,456.7
           
At December 31 (Millions)          
Total assets $12,646.7
 $12,285.6
 $12,022.6
 $11,661.3
 $10,170.7
Long-term debt and capital lease
     obligations (including current maturities)
 $5,233.6
 $5,258.8
 $5,276.8
 $5,022.0
 $4,053.5
           


CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA
    
  (Millions of Dollars) (a) 
  March June 
Three Months Ended 2014 2013 2014 2013 
Operating revenues $1,226.7
 $1,004.6
 $905.7
 $880.5
 
Operating income $221.8
 $173.1
 $144.2
 $124.2
 
Earnings available for common
     stockholder
 $127.0
 $104.4
 $90.0
 $72.8
 
          
  September December 
Three Months Ended 2014 2013 2014 2013 
Operating revenues $937.8
 $964.6
 $989.2
 $950.5
 
Operating income $156.2
 $164.6
 $128.2
 $144.0
 
Earnings available for common
     stockholder
 $89.8
 $98.9
 $69.9
 $83.9
 
As of or for Year Ended December 31          
(in millions) 
2017 (1)
 2016 2015 2014 2013
Operating revenues $3,711.7
 $3,792.8
 $3,854.1
 $4,059.4
 $3,800.2
Net income attributed to common shareholder 335.6
 364.3
 375.7
 376.7
 360.0
Total assets 13,121.6
 13,371.5
 13,139.6
 12,597.2
 12,207.2
Long-term debt and capital lease obligations (excluding current portion) 5,236.1
 5,417.6
 5,351.3
 4,875.2
 4,876.7

(a)
(1)
Quarterly resultsIncludes the impact of operations are not directly comparable becausethe transfer of seasonalour investment in ATC to another subsidiary of WEC Energy Group and other factors.the impact of the transfer of net assets to UMERC. See Management's Discussion and Analysis of Financial Condition and Results of Operations.Note 4, Related Parties, for more information on these transactions.


2017 Form 10-K3631Wisconsin Electric Power Company
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2014 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 17, Segment Information, for more information on our reportable business segments.

CORPORATE STRATEGYEffective January 1, 2017, our customers (other than Tilden) and electric distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility. See Note 4, Related Parties, and Note 21, Regulatory Environment, for more information.

Business OpportunitiesEffective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information. In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. See Note 3, Dispositions, for more information.

Corporate Strategy

Our goal is to continue to build and sustain long-term value for customers and shareholders by focusing on the fundamentals of our business: reliability; operating efficiency; financial discipline; customer care; and safety.

Reshaping Our Generation Fleet

WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. WEC Energy Group expects to retire approximately 1,800 MW of coal generation by 2020 across its electric utilities, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. See Note 6, Property, Plant, and Equipment, for information related to the planned retirements of our Pleasant Prairie power plant and PIPP as part of WEC Energy Group's plan.

Reliability

We have two primary investment opportunitiesmade significant reliability-related investments in recent years, and earnings streams:plan to continue strengthening and modernizing our regulatedgeneration fleet and distribution networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized by PA Consulting Group, an independent consulting firm, as the most reliable utility businessin the United States in 2017 and, our investmentfor the seventh year in ATC.a row, as the most reliable utility in the Midwest.

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

We have a 23.0% ownership interest in ATC, a MISO member company regulated by FERC. Our investment in ATC totaled $372.9 million ascontinually look for ways to optimize the operating efficiency of December 31, 2014, and our 2014 pre-tax earningscompany. For example, we received approval from ATC totaled $57.9 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 $110 millionchanges at the Elm Road Generating Station to enable the facility to burn coal from the Powder River Basin located in ATC asthe western United States. The 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 continuesin a better position to investbe called upon in transmission projects.the MISO Energy Markets, resulting in lower fuel costs for our customers.


RESULTS OF OPERATIONS

EARNINGS

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

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


2017 Form 10-K3732Wisconsin Electric Power Company
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We also made progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

WEC Energy Group continues to focus on integrating and improving business processes and consolidating its IT infrastructure across all of its companies. We expect these efforts to continue to drive operational efficiency and to put us in position to effectively support plans for future growth.

Financial Discipline

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

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, 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 and Bostco's remaining real estate holdings.

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, demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

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 to improve customer satisfaction.

Safety

We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. WEC Energy Group's corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.

RESULTS OF OPERATIONS

Consolidated Earnings

Our consolidated earnings for the years ended December 31, 2017, 2016, and 2015 were $335.6 million, $364.3 million, and $375.7 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

ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)20142017 Form 10-K33Wisconsin Electric Power Company
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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, 2017, 2016, and 2015 was $625.6 million, $629.5 million, and $648.9 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

Effective January 1, 2017, we transferred our electric customers (other than Tilden) located in the Upper Peninsula of Michigan to UMERC. See Note 4, Related Parties, for more information.
  Year Ended December 31
(in millions) 2017 2016 2015
Electric revenues $3,336.2
 $3,440.6
 $3,454.4
Fuel and purchased power 1,064.3
 1,091.8
 1,154.4
Total electric margins 2,271.9
 2,348.8
 2,300.0
       
Natural gas revenues 375.5
 352.2
 399.7
Cost of natural gas sold 222.1
 200.3
 244.6
Total natural gas margins 153.4
 151.9
 155.1
       
Total electric and natural gas margins 2,425.3
 2,500.7
 2,455.1
       
Other operation and maintenance 1,358.5
 1,430.2
 1,384.9
Depreciation and amortization 331.6
 325.4
 304.0
Property and revenue taxes 109.6
 115.6
 117.3
Operating income $625.6
 $629.5
 $648.9

The following table summarizes our consolidated earnings during 2014, 2013shows a breakdown of other operation and 2012:

maintenance:
  2014 2013 2012
  (Millions of Dollars)
Utility Gross Margin      
Electric (See below) $2,187.1
 $2,164.2
 $2,103.6
Gas (See below) 181.6
 173.6
 157.4
Steam 30.0
 26.0
 20.8
Total Gross Margin 2,398.7
 2,363.8
 2,281.8
Other Operating Expenses      
Other operation and maintenance 1,356.4
 1,417.3
 1,327.8
Depreciation and amortization 295.7
 278.6
 257.6
Property and revenue taxes 113.6
 110.0
 113.1
Total Operating Expenses 1,765.7
 1,805.9
 1,698.5
Treasury Grant 17.4
 48.0
 —
Operating Income 650.4
 605.9
 583.3
Equity in Earnings of Transmission Affiliate 57.9
 60.2
 57.6
Other Income and Deductions, net 8.7
 17.4
 32.3
Interest Expense, net 116.5
 121.4
 113.2
Income Before Income Taxes 600.5
 562.1
 560.0
Income Tax Expense 222.6
 200.9
 192.7
Preferred Stock Dividend Requirement 1.2
 1.2
 1.2
Earnings Available for Common Stockholder $376.7
 $360.0
 $366.1
  Year Ended December 31
(in millions) 2017 2016 2015
Operation and maintenance not included in lines items below $488.3
 $500.2
 $502.9
We Power (1)
 513.0
 513.2
 510.7
Transmission (2)
 251.9
 273.8
 272.3
Regulatory amortizations and other pass through expenses (3)
 96.7
 96.6
 99.0
Earnings sharing mechanism 0.1
 21.1
 —
Other 8.5
 25.3
 —
Total other operation and maintenance $1,358.5
 $1,430.2
 $1,384.9

(1)
Represents costs associated with the We Power generation units, including operating and maintenance, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During 2017, 2016, and 2015, $535.1 million, $528.4 million, and $483.4 million, respectively, of both lease and operating and maintenance costs were billed to us, with the difference in costs billed or incurred and expenses recognized, either 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 2017, 2016, and 2015, $303.8 million, $335.3 million, and $319.3 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.



2017 Form 10-K3834Wisconsin Electric Power Company
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ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2014 with similartables provide information for 2013 and 2012, including a summary of electric operating revenues and electric saleson delivered volumes by customer class:class and weather statistics:
  Year Ended December 31
  
MWh (in thousands)
Electric Sales Volumes 2017 2016 2015
Customer class      
Residential 7,648.5
 8,136.6
 7,789.3
Small commercial and industrial 8,768.4
 9,061.1
 8,835.9
Large commercial and industrial 8,340.3
 9,217.6
 9,492.0
Other 144.9
 143.4
 147.7
Total retail 24,902.1
 26,558.7
 26,264.9
Wholesale 1,600.2
 1,134.2
 1,234.0
Resale 8,144.5
 8,282.1
 8,577.6
Total sales in MWh 34,646.8
 35,975.0
 36,076.5

  Electric Revenues and Gross Margin MWh Sales
Electric Utility Operations 2014 2013 2012 2014 2013 2012
  (Millions of Dollars) (Thousands)
Customer Class            
Residential $1,199.3
 $1,208.6
 $1,163.9
 7,946.3
 8,141.9
 8,317.7
Small Commercial/Industrial 1,052.9
 1,048.0
 1,013.6
 8,805.1
 8,860.4
 8,860.0
Large Commercial/Industrial 637.0
 711.9
 744.3
 7,393.3
 8,673.4
 9,710.7
Other - Retail 23.0
 23.4
 22.8
 148.7
 152.3
 154.8
Total Retail 2,912.2
 2,991.9
 2,944.6
 24,293.4
 25,828.0
 27,043.2
Wholesale - Other 131.9
 143.7
 144.4
 1,852.8
 1,953.5
 1,566.6
Resale - Utilities 264.1
 143.2
 53.4
 6,497.9
 4,382.7
 1,642.4
Other Operating Revenues 87.8
 28.4
 51.5
 —
 —
 —
Total 3,396.0
 3,307.2
 3,193.9
 32,644.1
 32,164.2
 30,252.2
Electric Customer Choice (a) 5.1
 1.5
 —
 2,440.0
 813.0
 —
Total, including electric customer choice 3,401.1
 3,308.7
 3,193.9
 
 
 
             
             
Fuel and Purchased Power            
Fuel 656.6
 611.1
 541.6
      
Purchased Power 557.4
 533.4
 548.7
      
Total Fuel and Purchased Power 1,214.0
 1,144.5
 1,090.3
      
Total Electric Gross Margin $2,187.1
 $2,164.2
 $2,103.6
      
             
Weather -- Degree Days (b)            
Heating (6,601 Normal)       7,616
 7,233
 5,704
Cooling (732 Normal)       464
 688
 1,041
  Year Ended December 31
  
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 2015
Customer class      
Residential 344.3
 341.7
 341.2
Commercial and industrial 193.4
 186.3
 194.5
Total retail 537.7
 528.0
 535.7
Transport 314.2
 323.8
 306.9
Total sales in therms 851.9
 851.8
 842.6

  Year Ended December 31
  Degree Days
Weather * 2017 2016 2015
Heating (6,574 normal) 5,908
 6,068
 6,468
Cooling (714 normal) 772
 991
 622

(a)
*		Represents distribution sales for customers who have purchased powerNormal degree days are based on a 20-year moving average of monthly temperatures 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.

2017 Compared with 2016

Electric Utility Revenues and SalesMargins

2014 vs. 2013:   OurElectric utility margins decreased $76.9 million during 2017, compared with 2016. The significant factors impacting the lower electric utility operating revenues increased by $92.4 million, or 2.8%, when compared to 2013. The most significant factors that caused a change in revenuesmargins were:

A $120.9 million increase in sales for resale because of increased sales into the MISO Energy Markets as a result of Michigan's alternative electric supplier program and increased availability of our generating units. The margin on these sales is used to reduce fuel costs for our retail customers.
A $78.4$74.1 million decrease in large commercial/industrialrelated to lower sales because of the two iron ore mines switching to an alternative electric supplier in September 2013. See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Michigan Business, for a discussion of the impact of industry restructuring in Michigan on our electric sales.
A $59.4 million increase in other operating revenues,volumes during 2017, primarily driven by unfavorable weather, lower overall retail use per customer, and the recognitiontransfer of $56.4 millioncustomers and their related sales to revenues underUMERC. Cooler summer and warmer winter weather in 2017, as well as an additional day of sales during 2016 due to leap year, contributed to the System Support Resource (SSR) agreement with MISO. See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Michigan Business -- SSR Payments for further discussion.
Wisconsin net retail pricing increases of $38.3 million, which are primarily related to our 2013 Wisconsin Rate Case.
Unseasonably cool summer weather which decreased electric revenues by an estimated $45.8 million.


39Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

decrease. As measured by cooling degree days, 20142017 was 36.6%22.1% cooler than normal,2016. As measured by heating degree days, 2017 was 2.6% warmer than 2016.

A $25.9 million decrease related to SSR payments we refunded to MISO as directed by a FERC order received in October 2017. The FERC order reduced the costs eligible for reimbursement to us for the operation and 32.6% cooler than 2013 duemaintenance of our PIPP units under an SSR agreement we have with MISO. A portion of these payments was returned to mild secondus through the MISO allocation process and third quarters. The unfavorable impact of the cool summer weather was partially offset by the cold winter weather. Residential sales decreased by 2.4%reduced transmission expense as discussed below. See Note 21, Regulatory Environment, primarily duefor more information.

A $4.3 million decrease in margins related to the weather. Sales to our large commercial/industrial customers decreased by 14.8% primarily because of the loss of the two iron ore mines located in the Upper Peninsula of Michigan. IfIn November 2016, one of the mines are excluded, sales to our large commercial/industrial customers decreased 1.1%. The two iron ore mines which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smallerclosed. With the return of the mines as retail customers switched to an alternative electric supplier.

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

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

Wisconsin net retail pricing increases of $115.6 million ($177.7 million less $62.1 million related to Section 1603 Renewable Energy Treasury Grant (Treasury Grant) bill credits), which are primarily related to our 2013 Wisconsin Rate Case. For information on the Treasury Grant and the rate order in the 2013 rate case, see Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments and -- Rates and Regulatory Matters, respectively.
An $89.8 million increase in sales for resale due to increased sales into the MISO Energy Markets as a result of increased availability of our generating units.
A $48.0 million decrease in large commercial/industrial sales due to the two iron ore mines that switched to an alternative electric supplier effective September 1, 2013.
A $23.1 million decrease in other operating revenues, primarily driven by the amortization of $25.9 million in 2012 related to proceeds we received as part of a settlement with the United States Department of Energy (DOE) regarding the DOE's failure to remove spent nuclear fuel from Point Beach.
A return to more normal summer weather as compared to 2012 that decreased electric revenues by an estimated $17.7 million.

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


Electric Fuel and Purchased Power Expenses

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

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


2017 Form 10-K4035Wisconsin Electric Power Company
Table of Contents

A $3.5 million decrease in steam margins driven by the sale of the MCPP in April 2016. See Note 3, Dispositions, for more information.
These decreases in margins were partially offset by $36.5 million of lower capacity payments to a counterparty during 2017, related to improved contract terms.

Natural Gas Utility Margins

Natural gas utility margins increased $1.5 million during 2017, compared with 2016. The most significant factor impacting the higher natural gas utility margins was higher retail sales volumes, primarily driven by higher overall retail use per customer and customer growth. The higher margins were partially offset by an additional day of sales during 2016 due to leap year.

Operating Income

Operating income at the utility segment decreased $3.9 million during 2017, compared with 2016. This decrease was driven by the $75.4 million net decrease in margins discussed above, partially offset by $71.5 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).

We experienced lower overall operating expenses related to synergy savings resulting from WEC Energy Group's acquisition of Integrys. The significant factors impacting the decrease in operating expenses during 2017, compared with 2016, were:

A $21.9 million decrease in transmission expenses, driven by a FERC order to reduce SSR costs related to PIPP, as discussed under electric utility margins.

A $21.0 million decrease in expenses related to our earnings sharing mechanism in place. See the PSCW conditions of approval related to the Integrys acquisition in Note 2, Acquisitions, for more information.

A $19.1 million decrease in electric and natural gas distribution expenses, primarily related to the transfer of electric customers and their related sales to UMERC, lower metering costs, and other cost savings.

A $16.8 million decrease in expenses related to charitable projects supporting our customers and the communities within our service territories.

These decreases in operating expenses were partially offset by a $10.9 million gain recorded in April 2016 related to the sale of the MCPP. See Note 3, Dispositions, for more information on the sale of the MCPP.

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.


ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)20142017 Form 10-K


Gas Utility Revenues, Gross Margin and Therm Deliveries

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

Gas Utility Operations 2014 2013 2012
  (Millions of Dollars)
       
Operating Revenues $614.2
 $451.9
 $385.1
Cost of Gas Sold 432.6
 278.3
 227.7
Gross Margin $181.6
 $173.6
 $157.4

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

  Gross Margin Therm Deliveries
Gas Utility Operations 2014 2013 2012 2014 2013 2012
  (Millions of Dollars) (Millions)
Customer Class            
Residential $121.2
 $117.8
 $106.1
 399.3
 380.8
 294.3
Commercial/Industrial 41.1
 37.5
 33.0
 236.2
 210.9
 165.3
Interruptible 0.4
 0.5
 0.5
 4.9
 5.4
 5.0
Total Retail 162.7
 155.8
 139.6
 640.4
 597.1
 464.6
Transported Gas 17.3
 16.5
 16.5
 343.1
 327.6
 344.5
Other 1.6
 1.3
 1.3
 —
 —
 —
Total $181.6
 $173.6
 $157.4
 983.5
 924.7
 809.1
             
Weather -- Degree Days (a)            
Heating (6,601 Normal)       7,616
 7,233
 5,704

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

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

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


Other Operation and Maintenance Expense

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

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


4136Wisconsin Electric Power Company
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ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

Operating Income

2013 vs. 2012:   Our other operation and maintenance expense increased by $89.5Operating income at the utility segment decreased $19.4 million or approximately 6.7%, whenduring 2016, compared to 2012. This increasewith 2015. The decrease was primarily driven by the reinstatement of $148.0$65.0 million of regulatory amortizations,higher operating expenses, partially offset by the $45.6 million net increase 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.margins discussed above.


Depreciation and Amortization ExpenseThe significant factors impacting the increase in operating expenses during 2016, compared with 2015, were:

2014 vs. 2013:   Depreciation and Amortization expense increased by $17.1A $25.3 million or approximately 6.1%, when compared to 2013. This increase was primarily because of an overall increase in utility plant inexpenses related to charitable projects supporting our customers and the communities within our service as a result of the biomass plant that went into service in November 2013. For additional information on the biomass facility, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Renewables, Efficiency, and Conservation.territories.

2013 vs. 2012:   DepreciationA $21.4 million increase in depreciation and Amortization expense increasedamortization, driven by $21.0 million, or approximately 8.2%, when compared to 2012. This increase was primarily because of an overall increase in utility plant in service. In addition to the biomass facility that went into service in November 2013, the emission control equipment for units 5 and 6 of the Oak Creek Air Quality Control System (AQCS) project went into service in March 2012, and for units 7 and 8 in September 2012.


Treasury Grant

During 2014,2015, we recognized $17.4 million of income related to a Treasury Grant associated with the completion of the biomass plant, compared to $48.0 million in 2013. The lower grant income corresponds to the lower bill credits provided to our retail electric customers in Wisconsin in 2014. For additional information on the Treasury Grant, see Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments.


Other Income and Deductions, net

Other Income and Deductions, net 2014 2013 2012
  (Millions of Dollars)
       
AFUDC - Equity $4.4
 $17.6
 $34.9
Gain on Property Sales 4.3
 0.8
 0.3
Other, net —
 (1.0) (2.9)
Total Other Income and Deductions, net $8.7
 $17.4
 $32.3

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

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



42Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

Interest Expense, net

Interest Expense, net 2014 2013 2012
  (Millions of Dollars)
       
Gross Interest Costs $118.3
 $128.8
 $127.7
Less: Capitalized Interest 1.8
 7.4
 14.5
Interest Expense, net $116.5
 $121.4
 $113.2

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

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


Income Tax Expense

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

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


LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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

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

Operating Activities

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

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

43Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

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

Investing Activities

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

A $21.1 million expense related to our earnings sharing mechanism in cost of removal, net of salvage ofplace, effective January 1, 2016.

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.

Equity in Earnings of Transmission Affiliate
  Year Ended December 31
(in millions) 2017 2016 2015
Equity in earnings of transmission affiliate $—
 $55.5
 $47.8

2017 Compared with 2016

At December 31, 2016, we owned approximately 23% of ATC. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information.

2016 Compared with 2015

Earnings from our ownership interest in ATC increased $7.7 million during 2016, compared with 2015. This increase was primarily due to the negative impact on our 2015 earnings from a decreasedecision issued by an administrative law judge in customer advances for construction projects.December 2015 regarding complaints related to ATC's ROE.

Consolidated Other Income, Net
  Year Ended December 31
(in millions) 2017 2016 2015
AFUDC – Equity $3.1
 $4.2
 $5.7
Interest income 2.3
 2.2
 2.2
Other, net 14.3
 2.7
 3.3
Other income, net $19.7
 $9.1
 $11.2

2017 Compared with 2016

Other income, net increased $10.6 million during 2017, compared with 2016. The increase was driven by higher gains on property sales during 2017, compared to 2016, and the expenses we incurred in 2016 related to the disposition of certain non-utility real estate assets. These increases were partially offset by lower AFUDC during 2017.

Consolidated Interest Expense
  Year Ended December 31
(in millions) 2017
2016
2015
Interest expense $117.3
 $117.6
 $119.0

2017 Form 10-K37Wisconsin Electric Power Company
Table of Contents


Income Tax Expense
  Year Ended December 31
  2017
2016
2015
Effective tax rate 36.2% 36.6% 36.0%

2017 Compared with 2016

2013 vs. 2012:   Cash usedOur effective tax rate was 36.2% 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 as2017 compared to 2012,36.6% in 2016. This decrease in our effective tax rate was 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 isdue to increased renewable energy credits related to wind projects and favorable compensation expense. Preliminarily, we expect our 2018 annual effective tax rate to be between -5% and -4%, which includes an estimated 27% effective tax rate benefit due to the 2012 releaseflow through of restricted cash through bill credits and the reimbursement of costs associatedtax repairs in connection with the proceeds we received fromWisconsin settlement. See Note 21, Regulatory Environment, for more information on the settlementWisconsin settlement. Excluding the impact of the tax repairs, the 2018 range would be between 22% and 23%. See Note 12, Income Taxes, for more information.

2016 Compared with the DOE.2015

Financing ActivitiesOur effective tax rate was 36.6% in 2016 compared with 36.0% in 2015. This increase in our effective tax rate was primarily due to Treasury Grant activity in 2015.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows for the years ended December 31:
(in millions) 2017 2016 2015 Change in 2017 Over 2016 Change in 2016 Over 2015
Cash provided by (used in):          
Operating activities $698.0
 $848.4
 $674.4
 $(150.4) $174.0
Investing activities (568.2) (436.8) (520.2) (131.4) 83.4
Financing activities (132.9) (423.3) (151.1) 290.4
 (272.2)

Operating Activities

2017 Compared with 2016

Net cash provided by operating activities decreased $150.4 million during 2017, compared with 2016, driven by:

A $171.9 million net decrease in cash related to $71.7 million of cash paid for income taxes during 2017, compared with $100.2 million of cash received during 2016. This decrease in cash was primarily due to the extension of bonus depreciation in December 2015, which resulted in the receipt of an income tax refund during 2016.

A $149.8 million decrease in cash related to lower overall collections from financing activities:customers during 2017, compared with 2016. Collections from customers decreased primarily because of unfavorable weather and the loss of sales from the transfer of customers to UMERC in 2017.

Cash distributions provided by ATC of $38.4 million during 2016. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information.
  2014 2013 2012
  (Millions of Dollars)
       
Dividends to Wisconsin Energy $(390.0) $(340.0) $(179.6)
Net Increase in Debt 81.9
 18.4
 0.1
Other 11.7
 10.1
 (0.5)
Cash Used in Financing $(296.4) $(311.5) $(180.0)

These decreases 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.


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A $56.9 million increase in cash from lower payments for operating and maintenance costs. During 2017, our payments related to transmission, electric and natural gas distribution, and charitable projects decreased.

2014 vs. 2013:A $32.5 million net increase in cash resulting from lower payments for fuel and purchased power due to the transfer of electric customers to UMERC. This increase in cash was partially offset by higher payments for natural gas,primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 8.9% during 2017, compared with 2016.

2016 Compared with 2015

Net cash provided by operating 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 fuel and purchased power, due to lower commodity prices and warmer weather during the 2016 heating season. The average per-unit cost of 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, compared with 2015.

A $29.1 million increase in cash due to lower collateral requirements during 2016, compared with 2015, driven by an increase in the fair value of our derivative instruments. See Note 14, 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.

A $55.8 million decrease in cash driven by higher payments for operating and maintenance costs during 2016.

Investing Activities

2017 Compared with 2016

Net cash used in investing activities increased $131.4 million during 2017, compared with 2016, driven by:

A $126.6 million increase in cash paid for capital expenditures during 2017, compared with 2016, which is discussed in more detail below.

Cash of $13.1 million received during 2016 related to transfers of certain software to WBS. There were no similar transfers in 2017.

An $8.8 million decrease in the proceeds received from the sale of assets during 2017, compared with 2016. See Note 3, Dispositions, for more information.

These increases in net cash used in investing activities were partially offset by $16.1 million of capital contributions paid to ATC during 2016. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group.

2016 Compared with 2015

Net cash used in investing activities decreased $83.4 million during 2016, compared with 2015, driven by:

A $49.7 million decrease in cash paid for capital expenditures during 2016, compared with 2015, which is discussed in more detail below.

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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 during 2016, compared with 2015, driven by the continued investment in equipment and facilities by ATC to improve reliability.

Capital Expenditures

Capital expenditures for the years ended December 31 were as follows:
(in millions) 2017 2016 2015 Change in 2017 Over 2016 Change in 2016 Over 2015
Capital expenditures $596.1
 $469.5
 $519.2
 $126.6
 $(49.7)

2017 Compared with 2016

The increase in cash paid for capital expenditures during 2017, compared with 2016, was driven by upgrades to our electric and natural gas distribution systems, including main replacement projects and an advanced metering infrastructure program, as well as various projects at the OCPP.

See Capital Resources and Requirements – Capital Requirements – Capital Expenditures and Significant Capital Projects below for more information.

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.

Financing Activities

2017 Compared with 2016

Net cash used in financing activities was $296.4decreased $290.4 million during 20142017, compared with 2016, driven by:

A $215.0 million decrease in dividends paid to $311.5 millionour parent during 2013.2017, compared with 2016. During 2014,2016, we paid $50.0 million more in special dividends to Wisconsin Energyour parent to balance our capital structure.

A $75.0 million equity contribution received from our parent to balance our capital structure which was more than offset by a $63.5in 2017.

A $36.9 million increase in short-term debt.net borrowings of commercial paper during 2017, compared with 2016.

2013 vs. 2012:   CashThese decreases in net cash used in financing activities was $311.5were partially offset by a $17.4 million increase in repayments provided to our parent during 2017 related to our subsidiary's note payable, compared with 2016.

2016 Compared with 2015

Net cash used in financing activities increased $272.2 million during 20132016, compared with 2015, 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 to our parent during 2016, compared with 2015. 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.

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CAPITAL RESOURCES AND REQUIREMENTSThese increases in net cash used for financing activities were 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.

Working CapitalSignificant Financing Activities

As of December 31, 2014, our current liabilities exceeded our current assets by approximately $214.4 million. Included in our current liabilities is approximately $355.6 million of long-term debt and capital lease obligations due currently. We do not expect this to have any impactFor more information on our liquidity because we believe we have an adequate back-up linefinancing activities, see Note 10, Short-Term Debt and Lines of credit in place for ongoing operations. We also have access to the capital markets to finance our construction programCredit, and to refinance current maturities of long-term debt if necessary.Note 11, Long-Term Debt and Capital Lease Obligations.

Capital Resources and Requirements

Capital Resources

Liquidity

We anticipate meeting our capital requirements for 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.


44Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement,arrangements, 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, 2014, we had approximately $494.9 million of available, undrawn lines under our bank back-up credit facility. As of December 31, 2014, we had approximately $306.8 million of commercial paper outstanding that was supported by the available line of credit. During 2014, our maximum commercial paper outstanding was $401.0 million with a weighted-average interest rate of 0.22%. For additional information regarding our commercial paper balances during 2014, see Note K -- Short-Term Debt in the Notes to Consolidated Financial Statements.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facility asSee Note 10, Short-Term Debt and Lines of December 31, 2014:Credit, for more information on our credit facility.

Total Facility Letters of Credit Credit Available 
Facility
Expiration
(Millions of Dollars)  
       
$500.0 $5.1
 $494.9
 December 2019
At December 31, 2017, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 11, Long-Term Debt and Capital Lease Obligations, for more information on our long-term debt.

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

This facility has a renewal provisionAs of December 31, 2017, our current liabilities exceeded our current assets by $148.0 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for two one-year extensions, subjectour ongoing operations. We also believe that we can access the capital markets to lender approval.finance our construction programs and to refinance current maturities of long-term debt, if necessary.

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

Capitalization Structure 2014 2013
  (Millions of Dollars)
         
Common Equity $3,412.8
 37.9% $3,406.8
 38.3%
Preferred Stock 30.4
 0.3% 30.4
 0.3%
Long-Term Debt (a) 2,415.5
 26.8% 2,467.3
 27.8%
Capital Lease Obligations (a) 2,818.1
 31.3% 2,791.5
 31.4%
Short-Term Debt (b) 329.2
 3.7% 197.3
 2.2%
Total $9,006.0
 100.0%
$8,893.3
 100.0%
         
(a) Includes current maturities        
(b) Includes subsidiary note payable to Wisconsin Energy    

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

We are the obligor under two series of tax exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of December 31, 2014, the repurchased bonds were still outstanding, but were not reported as long-term debt or included on the Consolidated Statements of Capitalization because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.


45Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

Bonus Depreciation Provisions

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

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We 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, 2014, we estimate that the collateral or the termination payments required under these agreements totaled approximately $195.3 million. Generally, collateral may be provided by a Wisconsin Energy guaranty, letter of credit or cash.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 December 2014,July 2017, Moody's downgraded our senior unsecured rating to A2 from A1 and affirmed our ratings (commercialP-1 commercial paper P-1; senior unsecured, A1) andrating. We do not believe the change in rating will have a material impact on our stable ratings outlook.ability to access capital markets.

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

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

If we are unable to successfully take actions to manage any adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us to issue future debt securities and certain other types of financing and could increase borrowing costs under our credit facility.

Capital Requirements

Capital Expenditures:   Our estimated capital expenditures for the next three years are as follows:
 (Millions of Dollars)
2015$496.2
2016472.7
2017498.4
Total$1,467.3
Contractual Obligations

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

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

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

46Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

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

Off-Balance Sheet Arrangements:   We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For additional information, see Note F -- Variable Interest Entities in the Notes to Consolidated Financial Statements in this report.

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

2017:
  Payments Due by Period
Contractual Obligations (a) Total Less than 1 year 1-3 years 3-5 years More than 5 years
  (Millions of Dollars)
           
Long-Term Debt Obligations (b) $4,571.6
 $362.4
 $193.1
 $686.5
 $3,329.6
Capital Lease Obligations (c) 9,775.3
 439.2
 880.0
 851.6
 7,604.5
Operating Lease Obligations (d) 38.1
 5.2
 7.1
 4.3
 21.5
Purchase Obligations (e) 11,251.3
 796.5
 1,169.7
 966.3
 8,318.8
Other Long-Term Liabilities 884.3
 92.1
 183.8
 178.9
 429.5
Total Contractual Obligations $26,520.6
 $1,695.4
 $2,433.7
 $2,687.6
 $19,703.9
  
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)
 $4,873.3
 $362.8
 $460.8
 $491.3
 $3,558.4
Capital lease obligations (3)
 7,878.1
 398.7
 799.9
 792.7
 5,886.8
Operating lease obligations (4)
 34.7
 3.5
 5.3
 2.9
 23.0
Energy and transportation purchase obligations (5)
 9,954.9
 647.0
 1,132.0
 1,105.1
 7,070.8
Purchase orders (6)
 248.9
 42.8
 62.1
 46.7
 97.3
Pension and OPEB funding obligations (7)
 11.9
 4.0
 7.9
 —
 —
Total contractual obligations $23,001.8
 $1,458.8
 $2,468.0
 $2,438.7
 $16,636.3

(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 2020.

The table above does not include liabilitiesreflect estimated future payments related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimatemanufactured gas plant remediation liability of $18.5 million at December 31, 2017, as to the amount and periodtiming of related future payments at this time. For additionalare uncertain. We expect to incur costs annually to remediate these sites. See Note 19, Commitments and Contingencies, for more information regardingabout environmental liabilities.

AROs in the amount of $68.3 million are not included in the above table. Settlement of these liabilities refer to Note G -- Income Taxescannot be determined with certainty, but we believe the majority of these liabilities will be settled in the Notes to Consolidated Financial Statements in this report.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, impacts from the Tax Legislation,

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acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:
(in millions)  
2018 $598.5
2019 552.5
2020 807.5
Total $1,958.5

The majority of spending consists of upgrading our electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI) program. AMI is an integrated system of smart meters, communication networks and data management systems that enable two-way communication between utilities and customers.

Additionally, as part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar of up to 150 MW. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

Common Stock Matters

For information related to our common stock matters, see Note 8, Common Equity.

Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $1.4 billion as of December 31, 2017. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $8.3 million, $8.0 million, and $107.6 million to our pension and OPEB plans in 2017, 2016, and 2015, 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 10, Short-Term Debt and Lines of Credit, and Note 18, 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 environmentenvironments in which those businesses operate. These risks, described in further detail below, include but are not limited to:

Regulatory Recovery:   Recovery

We account for our regulated operations in accordance with accounting guidance for regulated entities.under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory authorities.commissions. Our primary regulator is the PSCW. See Note 21, 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

47Wisconsin Electric Power Company
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd)2014 Form 10-K

entity believes the recovery of thesethe costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recoveryregulators. Recovery of thesethe deferred costs in future rates is subject to the review and approval of thoseby our regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of thesethe 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

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and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2014,2017, our regulatory assets totaled $1,626.9were $1,984.9 million, and our regulatory liabilities totaled $615.9were $1,721.1 million.

Due to the Tax Legislation signed into law in December 2017, we remeasured our deferred taxes and recorded an estimated tax benefit of $1,065 million. This tax benefit will be returned to ratepayers through future refunds, bill credits, or reductions to other regulatory assets. See Note 12, Income Taxes, and Note 21, Regulatory Environment, for more information.

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 2014 rate order, the PSCW authorized continued use of the escrow method of accounting for bad debt costs. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceeds or is less than amounts allowed in rates.
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 2014, 20132017, 2016 and 2012,2015, as measured by degree days, may be found above in Results of Operations.

Interest Rate:Rates

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

Based on our variable rate debt outstanding as of at December 31, 2014. Borrowing levels under these arrangements vary from period to period depending on capital investments2017, and other factors. Future short-termDecember 31, 2016, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $2.1 million and payments will reflect both future short-term interest rates$1.6 million in 2017 and borrowing levels.

We performed an interest rate2016, respectively. This sensitivity analysis aswas performed assuming a constant level ofDecember 31, 2014 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2014, we had $306.8 million of commercial paper outstanding with a weighted-average interest rate of 0.25%. A one-percentage point changedebt during the period and an immediate increase in interest rates, would cause our annual interest expense to increase or decrease by approximately $3.1 million.with no other changes for the remainder of the period.

Marketable Securities Return: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

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

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

The fair value of our trust fund assets and expected long-term returns as of December 31, 2014were approximately:
(in millions) As of December 31, 2017 Expected Return on Assets in 2018
Pension trust funds $1,134.1
 7.00%
OPEB trust funds $220.1
 7.25%

  
As of
December 31, 2014
(Millions of Dollars)
 Expected Return on Assets in 2015
     
Pension trust funds $1,160.0
 7.00%
Other post-retirement benefits trust funds $224.9
 7.25%
2017 Form 10-K44Wisconsin Electric Power Company
Table of Contents


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.funds.

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 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).

As part of our 2013 Wisconsin Rate Case, the PSCW determined that 100% of the construction costs for the Oak Creek expansion units were prudently incurred by We Power, and approved the recovery in rates of more than 99.5% of these costs.

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

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

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

We Power assigned its warranty rights to us upon turnover of each of the Oak Creek expansion units. The warranty claim for costs incurred to repair steam turbine corrosion damage identified on both units was scheduled to go to arbitration in October 2013, but we entered into a settlement agreement with Bechtel in June 2013 resolving the claim, as well as several other warranty claims. This settlement did not have a material impact to our financial statements. All warranty claims between the Company and Bechtel have now been resolved, none of which had a material impact on our financial statements.


RATES AND REGULATORY MATTERS

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

General Rate Proceedings

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

A net bill increase related to non-fuel costs for our Wisconsin retail electric customers of approximately $2.7 million (0.1%) in 2015. This amount reflects receipt of SSR payments from MISO that are higher than anticipated when we filed our rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from the Treasury Grant we received in connection with the biomass facility. This $26.6 million is being returned to customers in the form of bill credits.
An electric rate increase for our Wisconsin retail electric customers of $26.6 million (0.9%) for 2016, related to the expiration of the bill credits provided to customers in 2015.
A rate decrease of $13.9 million (-0.5%) in 2015 related to a forecasted decrease in fuel costs. We will make an annual fuel cost filing, as required, for 2016.
A rate decrease of $10.7 million (-2.4%) for our natural gas customers in 2015, with no rate adjustment in 2016.
An increase of approximately $0.5 million (2.0%) for our downtown Milwaukee steam utility customers for 2015, with no rate adjustment in 2016.
An increase of approximately $1.2 million (7.3%) for our Milwaukee County steam utility customers for 2015, with no rate adjustment in 2016.

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

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

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

A net bill increase related to non-fuel costs for our Wisconsin retail electric customers of approximately $70 million (2.6%) for 2013. This amount reflects an offset of approximately $63 million (2.3%) of bill credits related to the proceeds of the Treasury Grant, including related tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133 million (4.8%) for 2013.

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An electric rate increase for our Wisconsin retail electric customers of approximately $28 million (1.0%) for 2014, and a $45 million (1.6%) reduction in bill credits.
Recovery of a forecasted increase in fuel costs of approximately $44 million (1.6%) for 2013.
A rate decrease of approximately $8 million (-1.9%) for our natural gas customers for 2013, with no rate adjustment in 2014. The rates reflected a $6.4 million reduction in bad debt expense.
An increase of approximately $1.3 million (6.0%) for our downtown Milwaukee steam utility customers for 2013 and another $1.3 million (6.0%) in 2014.
An increase of approximately $1 million (7.0%) in 2013 and $1 million (6.0%) in 2014 for our Milwaukee County steam utility customers.

These rate adjustments were effective January 1, 2013. In addition, our allowed return on equity remained at 10.4%. The PSCW also approved escrow accounting treatment for the Treasury Grant.

2012 Wisconsin Rate Case:   In May 2011, we filed an application with the PSCW to initiate rate proceedings. In lieu of a traditional rate proceeding, we requested an alternative approach, which resulted in no increase in 2012 base rates for our customers. In order for us to proceed under this alternative approach, we requested that the PSCW issue an order that, among other things:
Authorized us to suspend the amortization of $148 million of regulatory costs during 2012, with amortization to begin again in 2013.
Authorized $148 million of carrying costs and depreciation on previously approved air quality and renewable energy projects, effective January 1, 2012.
Authorized the refund of $26 million of net proceeds from our settlement of the spent nuclear fuel litigation with the DOE.

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

2012 and 2010 Michigan Rate Cases:In July 2011, we filed a $17.5 million rate increase request with the MPSC, primarily to recover the costs of environmental upgrades and OC 2. Pursuant to Michigan law, we self-implemented a $5.7 million interim electric base rate increase in January 2012. This increase was partially offset by a refund of $2.7million 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 July 2009, we filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. In July 2010, the MPSC issued its final order, approving a total increase of $23.5 million annually, or 14.2%. In August 2010, our largest customers, two iron ore mines, filed an appeal with the MPSC regarding this rate order. In October 2010, the MPSC ruled on the mines' appeal and reduced the rate increase by approximately $0.3 million annually. In November 2010, the mines filed a Claim of Appeal of the October 2010 order with the Michigan Court of Appeals. In May 2014, the Court of Appeals issued its decision affirming the MPSC orders in both the 2010 and 2012 rate cases. In August 2014, the mines filed an Application for Leave to Appeal with the Michigan Supreme Court, which Application was denied on February 3, 2015.

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

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

Wisconsin Fuel Proceedings

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


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Other Rate Matters

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

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

Renewables, Efficiency and Conservation:   In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. A utility's renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Our baseline renewable energy percentage is 2.27%. Under Act 141, we were required to increase our renewable energy percentage at least two percentage points to a level of 4.27% for the years 2010-2014. As of December 31, 2014, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. To comply with increasing requirements, we have constructed and contracted for several hundred megawatts of wind generation and constructed a 50 MW biomass facility at Domtar Corporation's Rothschild, Wisconsin paper mill site that went into commercial operation in November 2013. Wood waste and wood shavings are used to produce renewable electricity and the plant also supports Domtar's sustainable papermaking operations. The final cost of completing this project was $268.9 million, excluding AFUDC. We also own four wind sites, consisting of 200 turbines with an installed capacity of 338 MW and a dependable capability of 66 MW.

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

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

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


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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.


ELECTRIC SYSTEM RELIABILITY

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


ENVIRONMENTAL MATTERS

Overview

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

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

Air Quality

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

NAAQS

8-hour Ozone Standards:  In 2008, the EPA issued a more stringent 8-hour ozone standard, and made final attainment designations for this revised standard in 2012. Sheboygan County and the eastern portion of Kenosha County were designated as non-attainment areas. As a result, construction permitting for all of our Wisconsin power plants, except the Pleasant Prairie Power Plant, is expected to be subject to less stringent permitting requirements. In addition, modifications to these facilities should not be required to obtain emission offsets. So long as eastern Kenosha County remains an ozone non-attainment area, the Pleasant Prairie Power Plant will continue to be subject to more stringent permitting requirements and offset provisions.

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In April 2014, the U.S. District Court for the Northern District of California adopted a petition from environmental groups to require the EPA to propose a new ozone standard by 2014, and to finalize the standard by October 2015. On November 25, 2014, the EPA proposed to lower the 8-hour ozone standard from its current level of 75 parts per billion. As part of its proposal, the EPA requested comment on values from 60-70 parts per billion. The impact, if any, of a revised standard will depend on how much it is lowered, but could result in widespread areas of the country not being able to meet the new standard.

Fine Particulate Standard:   In 2009, the EPA designated three counties in southeast Wisconsin (Milwaukee, Waukesha and Racine) as not meeting the daily standard for PM2.5. In April 2012, the EPA proposed to determine that these three counties meet the PM2.5 standard, and proposed to suspend the requirement that the state submit a State Implementation Plan (SIP) including reasonably available control technology regulations. In February 2014, the EPA re-proposed this determination, and in April 2014, the EPA took action to redesignate the three counties to attainment. Our generating facilities in the counties are now subject to less stringent construction permitting requirements and emission offset provisions are no longer required for modifications to these facilities. In addition, in December 2012, the EPA issued a revised and more stringent annual PM2.5 standard. On December 18, 2014, the EPA determined that all areas of Wisconsin and Michigan's Upper Peninsula meet the revised standard and designated them as attainment areas. Therefore, we do not currently expect the lower standard to impose any additional requirements on our operations.

Sulfur Dioxide Standard: The EPA issued a new 1-Hour SO2 NAAQS that became effective in August 2010. This standard represents a significant change from the previous SO2 standard, and NAAQS in general, since attainment designations were to be based primarily on modeling rather than monitoring. Typically, attainment designations are based on monitored data. In May 2014, the EPA issued the proposed Data Requirements Rule that would establish procedures and timelines for implementation of the standard. The proposed rule describes the EPA's plans for allowing the states to use either monitoring or modeling to make designations.

We filed comments on the proposed rule with the EPA in July 2014, and proposed a special reliability exclusion for PIPP that would recognize our request to retire the facility, and would exclude it from further modeling or monitoring requirements and subsequent emission reductions. As proposed, the rule affords state agencies latitude in rule implementation. States would have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection). If the state chooses modeling and the sources in an area do not make reductions by 2017, and as a consequence the area is classified as non-attainment, then they would have to make emission reductions by 2023. Alternatively, if a state opted out of modeling and instead chose monitoring, and subsequently monitored non-attainment, then it would face a 2026 compliance date. A non-attainment designation could have negative impacts for a localized geographic area, including permitting constraints for the subject source and for other new or existing sources in the area.
We believe our fleet (with the exception of PIPP) is well positioned to meet this regulation once it is finalized. If PIPP is still operating in the 2021-2022 timeframe, it will likely need additional SO2 reductions in order to comply with the standard.

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

Mercury and Other Hazardous Air Pollutants: In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric generating units. We currently anticipate that only PIPP will require modifications, and are planning for the addition of a dry sorbent injection system for further control of mercury and acid gases at the plant to comply with MATS. In April 2013, we received a one year MATS compliance extension through April 16, 2016 from the MDEQ.

In addition, both Wisconsin and Michigan have mercury rules that require a 90% reduction of mercury, and compliance with those rules will no longer be required after the compliance date for MATS.
In January 2013, the EPA issued the National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Industrial Boiler MACT Rule). The Industrial

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

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

Cross-State Air Pollution Rule:   In August 2011, the EPA issued CSAPR, formerly known as the Clean Air Transport Rule. This rule was proposed to replace the Clean Air Interstate Rule (CAIR), which had been remanded to the EPA in 2008. The stated purpose of the CSAPR is to limit the interstate transport of emissions of NOx and SO2 that contribute to PM2.5 and ozone non-attainment in downwind states through a proposed allocation plan. In February 2012, the EPA issued final technical revisions to the rule and issued a draft final rule which together delay the implementation date for certain penalty provisions that could potentially impact the PIPP and increase the number of allowances issued to the states of Michigan and Wisconsin. We and a number of other parties sought judicial review of the rule. In April 2014, the United States Supreme Court issued a decision largely upholding the rule and remanding it for further proceedings consistent with the Court's order. Briefing on further challenges to the rule allowed by the U.S. Supreme Court decision is ongoing. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision that cleared the way for the EPA to begin implementing CSAPR on January 1, 2015. We expect that there will be sufficient allowances available for PIPP to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. We also expect to have excess allowances available to sell from our Wisconsin power plants. In light of these developments, we withdrew our challenge to CSAPR.

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

In June 2012, the EPA promulgated a Federal Implementation Plan that approves reliance on the CSAPR to satisfy electric generating unit BART requirements for NOx and SO2. In December 2012, the EPA approved 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. We believe we are well positioned to meet the requirements of the Clean Air Visibility rule based on air quality control system additions that are already in place or planned for our generating facilities.
Climate Change:   We continue to take measures to reduce our emissions of GHG. We support flexible, market-based strategies to curb GHG emissions, including emissions trading, emission offset projects and credit for early actions. We support an approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters. We, along with our affiliates, have taken, and continue to take, several steps to reduce our emissions of GHG, including:

Repowered the Port Washington Power Plant from coal to natural gas-fired combined cycle units.
Added coal-fired units as part of the Oak Creek expansion that are the most thermally efficient coal units in our system.
Increased our investment in energy efficiency and conservation.
Added renewable capacity.
Converting the fuel source at the VAPP from coal to natural gas, scheduled for completion in 2015.
Retired coal units 1-4 at PIPP.

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

In accordance with instructions from the President, the EPA is pursuing regulation of GHG emissions using its existing authority under the CAA. In September 2013, the EPA issued new proposed New Source Performance Standards with GHG limits for new fossil fueled power plants. The rule would not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines. Based upon currently available

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

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

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

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

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

Valley Power Plant Conversion:In August 2012, we announced plans to convert the fuel source for VAPP from coal to natural gas. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC. We received PSCW approval for this project in March 2014. Construction related to the conversion of the first two boilers was completed in November 2014, and the remaining two boilers are scheduled for completion in 2015.

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

Water Quality

Clean Water Act:   Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The EPA finalized rules for new facilities (Phase I) in 2001. The EPA issued a final Phase II rule that became effective on October 14, 2014. The new rule applies to all of our existing generating facilities with

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

The new Phase II rule allows facility owners to select from seven options available to meet the impingement mortality (IM) reduction standard. BTA determinations will be made over the next several years by the WDNR and MDEQ, subject to EPA oversight, when facility permits are reissued. Based upon our assessment, we believe that the existing technologies at our generating facilities will allow us to demonstrate that, other than VAPP, all of our facilities satisfy the IM BTA standard. During 2015 and 2016, we plan to install fish protection screens at VAPP that will meet the IM BTA standard.

The BTA determinations for entrainment mortality (EM) reduction will be made by the WDNR and MDEQ on a case-by-case basis. The new rule requires state permitting agencies to determine EM BTA on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our proposed intake modification at VAPP. We cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new requirements for our other generating facilities.

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

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

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

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

Land Quality

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


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

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

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


LEGAL MATTERS

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

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

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


INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

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

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

Michigan Business

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

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

Mining Company and Empire Iron Mining Partnership, owners of the two mines in the Upper Peninsula of Michigan, to resolve all objections these parties raised at the FERC and the MPSC related to Wisconsin Energy’s proposed acquisition of Integrys. The agreement forms the basis for a settlement agreement between the parties and includes the following provisions which directly impact us:
The Governor, the Attorney General and the owners of the mines will each file a letter with FERC stating that they do not have any objection to FERC’s approval of Wisconsin Energy's acquisition of Integrys, and will refrain from taking any action at FERC seeking to oppose, otherwise condition or delay consummation of the transaction. These letters have been filed with FERC.
The settlement agreement will request that the MPSC order approve Wisconsin Energy's acquisition of Integrys subject to the following conditions: (i) the closing of the sale of our Michigan electric distribution assets and PIPP to Upper Peninsula Power Company (UPPCO) contemporaneously with the closing of the acquisition of Integrys; (ii) the closing of the sale of Wisconsin Public Service Corporation’s Michigan electric distribution assets to UPPCO contemporaneously with the closing of the acquisition; and (iii) termination of the PIPP SSR agreement between MISO and us no later than the closing date of the acquisition. To this end, we have entered into a non-binding term sheet to sell these assets to UPPCO, which is described in more detail below. The Attorney General, the MPSC Staff and the owners of the mines will not seek or support any other conditions on granting of MPSC approval of our acquisition of Integrys. Wisconsin Public Service Corporation is a subsidiary of Integrys.

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

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

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

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

In January 2014, we entered into an SSR agreement (Suspension) with MISO to recover costs for operating and maintaining the units. The agreement was effective February 1, 2014, had a one year term, and specified monthly payments to us of $4.4 million to cover fixed costs. The agreement also provided for the payment of our variable costs to operate and maintain the plant. MISO filed the SSR agreement with FERC, and on April 1, 2014, FERC conditionally accepted the agreement as filed, subject to further review and FERC order. We began receiving SSR payments from MISO in the second quarter of 2014 retroactive to the agreement's effective date of February 1, 2014.

In addition, we issued a request for proposals regarding the potential purchase of PIPP in January 2014. We did not receive any valid proposals by the March 3, 2014 deadline. Based upon our evaluation and the lack of interest to purchase the plant, in April 2014, we filed a request with MISO to retire PIPP effective October 15, 2014. In May 2014, MISO informed us that they had determined the operation of all five units at PIPP was necessary for reliability purposes; therefore, the units would continue to be designated as SSR units.

We entered into a new SSR agreement (Retirement) with MISO, effective October 15, 2014, that covered the operating costs of PIPP through December 2015. The new SSR agreement also included, among other things, costs to comply with the MATS rule and a return on and of our investment in the plant. The new agreement is based on projected costs and is subject to a true-up mechanism. The estimated monthly payments under this agreement were approximately $8.1 million. On November 10, 2014, FERC accepted the new SSR agreement, but it is subject to further action.

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

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

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

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

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

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

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

Electric Transmission, Capacity and Energy Markets

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

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

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

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through Auction Revenue Rights (ARRs) and Financial Transmission Rights (FTRs). ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2014 through May 31, 2015. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.


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

Natural Gas Utility Industry

Restructuring in Wisconsin:The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas 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, workAll of our Wisconsin customer classes have competitive market choices and, therefore, can purchase natural gas directly from either an alternative retail natural gas supplier or their local natural gas utility.

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 natural gas to their facilities, we earn distribution revenues from them. As such, there is little impact on deregulationour net income from customers purchasing natural gas from an alternative retail natural gas supplier as natural gas costs are passed through to customers in rates on a one-for-one basis.

2017 Form 10-K45Wisconsin Electric Power Company
Table of the gas distribution industry by the PSCW continues to be on hold. Contents

Currently, we are unable to predict the impact of potential future deregulationindustry restructuring on our results of operations or financial position.


OTHER MATTERSEnvironmental Matters

Paris Generating Station Units 1See Note 19, Commitments and 4 Temporary Outage: Between 2000Contingencies, for a discussion of certain environmental matters affecting us, including rules and 2002, we replacedregulations relating to air quality, water quality, land quality, and climate change.

Other Matters

Tax Cuts and Jobs Act of 2017

On December 22, 2017, the blades on the four PSGS combustion turbine generators with blades that were approximately 7% more efficient. The work was performed as routine maintenance that we did not believe required a construction permit at the time and the plant has not been operated to use the potential additional capacity; however, in January 2013, the WDNR indicated that it considered this maintenance to be a modification requiring a construction permit. This matter has since been settled. In December 2013, Act 91Tax Legislation was signed into law in Wisconsin, creatinglaw. See Note 12, Income Taxes, and Note 21, Regulatory Environment,
for more information regarding its impact on us.

Bonus Depreciation Provisions

Bonus depreciation is an additional amount of first-year tax deductible depreciation that is awarded above what would normally be available. Based on the Protecting Americans from Tax Hikes Act of 2015, a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to Units 1 and 4, allowing those units to restart. We received an “after the fact” permit from the WDNR, and the Units are now50% bonus depreciation deduction was available for service. On October 24, 2014, the Sierra Club filed for a contested case hearing with the WDNR challengingassets placed in service during 2017. The increase in our federal tax depreciation from this permit.deduction significantly reduced our 2017 federal income tax payment.

In February 2013,On December 22, 2017, the Sierra Club filedTax Legislation was signed into law. This legislation modified the bonus depreciation deduction available for public utility property subject to rate-making by a contested case hearing with the WDNR in connection with the administration order issued in this matter, which was granted. However, a hearing has not yet been scheduled.


ACCOUNTING DEVELOPMENTS

New Pronouncements:government entity or public utility commission. See Note B -- Recent12, Income Taxes, for more information.
Critical Accounting Pronouncements in the Notes to Consolidated Financial Statements in this report for information on new accounting pronouncements.

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

In June 2014, we received approximately $76.2 million related to the Treasury Grant. The PSCW approved escrow accounting for the Treasury Grant and the proceeds we received that exceeded the amounts originally included in rates are being returned to customers in the form of bill credits.

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


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

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:

Regulatory Accounting:
Long-Lived Assets

We operate under rates establishedperiodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by statemanagement. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future.

We have evaluated future plans for our older fossil fuel generating units and federal regulatory commissions whichhave announced our plans for the retirement of certain older and less-efficient generating units. When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are designedconsidered probable of abandonment are expected to recovercease operations in the costnear term, significantly before the end of servicetheir original estimated useful lives. As a result, the remaining net book value of these assets can be significant. If a generating unit meets applicable criteria to be considered probable of abandonment, we assess the likelihood of recovery of the remaining carrying value of that generating unit at the end of each reporting period. If it becomes probable that regulators will not allow full recovery as well as a return on the remaining net book value of the abandoned generating unit, an impairment charge may be required. An impairment charge would be recorded if the remaining carrying value of the abandoned generating unit is greater than the present value of the amount expected to be recovered from ratepayers.

2017 Form 10-K46Wisconsin Electric Power Company
Table of Contents


We concluded that Pleasant Prairie power plant and provide a reasonable returnPIPP met the criteria to investors. The actionsbe considered probable of our regulators may allow us to defer costs that non-regulated entities would expense and accrue liabilities that non-regulated companies would not. Asabandonment as of December 31, 2014, we had $1,626.9 million in regulatory assets2017. We plan to ask for full cost recovery of and $615.9 million in regulatory liabilities. Ina full return on the future, if we move to market based rates, or ifremaining book value of the actions of our regulators change, we may concludegenerating units and have concluded that we are unable to follow regulatory accounting. In this situation, we would record the regulatory assetsno impairment was required related to unrecognized pension and OPEB coststhese assets 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.December 31, 2017.

See Note 6, Property, Plant, and Equipment, for more information on the units to be retired.

Pension and OPEB:   Our reportedOther Postretirement Employee Benefits

The 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, mortality and the discount rates used in determining the projected benefit obligation and pension costs.

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

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

Pension Plan Impact on
Actuarial Assumption Annual Cost
  (Millions of Dollars)
   
0.5% decrease in discount rate and lump sum conversion rate $5.0
0.5% decrease in expected rate of return on plan assets $5.5

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

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

and health care cost trends. Changes made to the provisions of the plans may also impact current and future OPEB costs. OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and the discount rates, used in 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.

The following table reflects OPEB plan sensitivities associated with changesshows how a given change in certain actuarial assumptions bywould impact the indicated percentage.projected benefit obligation and the reported net periodic pension cost. Each sensitivityfactor 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 2017
Pension Cost
Discount rate (0.5) $68.9
 $5.0
Discount rate 0.5 (60.2) (4.2)
Rate of return on plan assets (0.5) N/A
 5.5
Rate of return on plan assets 0.5 N/A
 (5.5)

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 2017 Postretirement
Benefit Cost
Discount rate (0.5) $22.6
 $0.6
Discount rate 0.5 (19.9) (0.1)
Health care cost trend rate (0.5) (12.4) (1.2)
Health care cost trend rate 0.5 14.3
 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 givendiscounted value of the plans' expected future benefit payments.

We establish our expected return on asset assumption holding all other assumptions constant.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 2017, 2016, and 2015. The actual rate of return on pension plan assets, net of fees, was 11.48%, 6.91%, and (0.6)%, in 2017, 2016, and 2015, respectively.


OPEB Plan Impact on
Actuarial Assumption Annual Cost
  (Millions of Dollars)
   
0.5% decrease in discount rate $0.6
0.5% decrease in health care cost trend rate in all future years $(2.9)
0.5% decrease in expected rate of return on plan assets $1.1
2017 Form 10-K47Wisconsin Electric Power Company
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In October 2014, the Societyselecting assumed health care cost trend rates, past performance and forecasts of Actuaries releasedhealth care costs are considered. For more information on health care cost trend rates and a new set of mortality tables (RP-2014) and an accompanying mortality improvement scale (MP-2014), which incorporates increasing life expectancy experience in the United States. Based on our initial review of the proposed tables,table showing future payments that we believeexpect to make for our pension and OPEB, obligationssee 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 increaseotherwise 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 approximately 6% if we adoptedour 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 tables. We will continue to evaluate the mortality assumptionsregulatory 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 future, as necessary, to conform toregulatory environment, earnings from our experience.electric and natural gas 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 to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2017, we had $1,984.9 million in regulatory assets and $1,721.1 million in regulatory liabilities. See Note 5, Regulatory Assets and Liabilities, for more information.

Unbilled Revenues:   Revenues

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 20142017 of approximately $4.1$3.7 billion included accrued utility revenues of $223.1$217.5 million as of December 31, 2014.2017.

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

2017 Form 10-K48Wisconsin Electric Power Company
Table of Contents

financial condition and results of operations. See Note 1(l), Income Taxes, and Note 12, 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(m), Fair Value Measurements in the Notes to Consolidated Financial Statements,, and
Note 1(n), Derivative Instruments, for information concerning potential market risks to which we are exposed.


2017 Form 10-K6349Wisconsin Electric Power Company
Table of Contents
2014 Form 10-K


ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
Year Ended December 31
      
 2014 2013 2012
 (Millions of Dollars)
      
Operating Revenues$4,059.4
 $3,800.2
 $3,613.3
      
Operating Expenses     
Fuel and purchased power1,228.1
 1,158.1
 1,103.8
Cost of gas sold432.6
 278.3
 227.7
Other operation and maintenance1,356.4
 1,417.3
 1,327.8
Depreciation and amortization295.7
 278.6
 257.6
Property and revenue taxes113.6
 110.0
 113.1
Total Operating Expenses3,426.4
 3,242.3
 3,030.0
      
Treasury Grant17.4
 48.0
 —
      
Operating Income650.4
 605.9
 583.3
      
Equity in Earnings of Transmission Affiliate57.9
 60.2
 57.6
Other Income and Deductions, net8.7
 17.4
 32.3
Interest Expense, net116.5
 121.4
 113.2
      
Income Before Income Taxes600.5
 562.1
 560.0
      
Income Tax Expense222.6
 200.9
 192.7
      
Net Income377.9
 361.2
 367.3
      
Preferred Stock Dividend Requirement1.2
 1.2
 1.2
      
Earnings Available for Common Stockholder$376.7
 $360.0
 $366.1
      
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Wisconsin Electric Power Company

Opinion on Financial Statements

We have audited the accompanying consolidated balance sheets and statements of capitalization of Wisconsin Electric Power Company and subsidiary (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating 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.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin
February 28, 2018

We have served as the Company's auditor since 2002.



2017 Form 10-K6450Wisconsin Electric Power Company
Table of Contents
2014 Form 10-K

B. CONSOLIDATED INCOME STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
 
ASSETS
    
 2014 2013
 (Millions of Dollars)
Property, Plant and Equipment   
Electric$9,024.8
 $8,717.0
Gas1,025.4
 977.4
Steam101.5
 102.0
Common339.6
 307.4
Other53.1
 56.8
 10,544.4
 10,160.6
Accumulated depreciation(3,406.1) (3,258.8)
 7,138.3
 6,901.8
Construction work in progress140.9
 101.9
Leased facilities, net2,215.0
 2,279.0
Net Property, Plant and Equipment9,494.2
 9,282.7
    
Investments   
Equity investment in transmission affiliate372.9
 354.1
Other0.2
 0.2
Total Investments373.1
 354.3
    
Current Assets   
Cash and cash equivalents24.0
 25.1
Accounts receivable, net of allowance for   
doubtful accounts of $46.8 and $39.7265.3
 335.7
Accounts receivable from related parties8.1
 9.1
Accrued revenues223.1
 240.7
Materials, supplies and inventories320.5
 281.0
Current deferred tax asset, net46.7
 75.8
Prepayments139.5
 137.7
Other19.0
 8.7
Total Current Assets1,046.2
 1,113.8
    
Deferred Charges and Other Assets   
Regulatory assets1,626.9
 1,370.3
Other106.3
 164.5
Total Deferred Charges and Other Assets1,733.2
 1,534.8
    
Total Assets$12,646.7
 $12,285.6
    
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.


65Wisconsin Electric Power Company
2014 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
 
CAPITALIZATION AND LIABILITIES
    
 2014 2013
 (Millions of Dollars)
Capitalization   
Common equity$3,412.8
 $3,406.8
Preferred stock30.4
 30.4
Long-term debt2,165.5
 2,167.3
Capital lease obligations2,712.5
 2,712.0
Total Capitalization8,321.2
 8,316.5
    
Current Liabilities   
Long-term debt and capital lease obligations due currently355.6
 379.5
Short-term debt306.8
 174.5
Subsidiary note payable to Wisconsin Energy22.4
 22.8
Accounts payable287.2
 273.8
Accounts payable to related parties87.8
 85.9
Accrued payroll and benefits87.1
 89.3
Other113.7
 132.3
Total Current Liabilities1,260.6
 1,158.1
    
Deferred Credits and Other Liabilities   
Regulatory liabilities615.9
 634.2
Deferred income taxes - long-term1,963.9
 1,794.5
Pension and other benefit obligations254.5
 160.1
Other230.6
 222.2
Total Deferred Credits and Other Liabilities3,064.9
 2,811.0
    
Commitments and Contingencies (Note Q)
 
    
Total Capitalization and Liabilities$12,646.7
 $12,285.6
    
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



66Wisconsin Electric Power Company
2014 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
       
  2014 2013 2012
  (Millions of Dollars)
Operating Activities      
Net income $377.9
 $361.2
 $367.3
Reconciliation to cash      
Depreciation and amortization 303.4
 288.3
 263.6
Deferred income taxes and investment tax credits, net 191.4
 193.6
 194.1
Contributions to qualified benefit plans —
 —
 (92.9)
Change in - Accounts receivable and accrued revenues 91.0
 (137.0) 64.3
Inventories (39.5) 31.2
 7.0
Other current assets (8.7) 0.7
 6.9
Accounts payable 18.2
 (29.4) 41.4
Accrued income taxes, net (7.5) 23.6
 89.4
Deferred costs, net (15.1) (8.7) 9.2
Other current liabilities (21.7) 21.8
 (2.4)
Other, net (26.6) 117.3
 (140.9)
Cash Provided by Operating Activities 862.8
 862.6
 807.0
       
Investing Activities      
Capital expenditures (540.9) (506.9) (575.8)
Investment in transmission affiliate (11.5) (9.2) (13.8)
Change in restricted cash —
 2.7
 42.8
Cost of removal, net of salvage (20.9) (32.0) (32.9)
Other, net 5.8
 (14.7) (25.9)
Cash Used in Investing Activities (567.5) (560.1) (605.6)
       
Financing Activities      
Dividends paid on common stock (390.0) (340.0) (179.6)
Dividends paid on preferred stock (1.2) (1.2) (1.2)
Issuance of long-term debt 250.0
 250.0
 250.0
Retirement of long-term debt (300.0) (300.0) —
Change in total short-term debt 131.9
 68.4
 (249.9)
Other, net 12.9
 11.3
 0.7
Cash Used In Financing Activities (296.4) (311.5) (180.0)
       
Change in Cash and Cash Equivalents (1.1) (9.0) 21.4
       
Cash and Cash Equivalents at Beginning of Year 25.1
 34.1
 12.7
       
Cash and Cash Equivalents at End of Year $24.0
 $25.1
 $34.1
       
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.


67Wisconsin Electric Power Company
2014 Form 10-K

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
     
  2014 2013
  (Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)   
Common stock - $10 par value; authorized   
65,000,000 shares; outstanding - 33,289,327 shares$332.9
 $332.9
Other paid in capital984.4
 965.1
Retained earnings2,095.5
 2,108.8
Total Common Equity3,412.8
 3,406.8
     
Preferred Stock (Note I)30.4
 30.4
     
Long-Term Debt    
Debentures (unsecured)6.00% due 2014—
 300.0
 6.25% due 2015250.0
 250.0
 1.70% due 2018250.0
 250.0
 4.25% due 2019250.0
 250.0
 2.95% due 2021300.0
 300.0
 6-1/2% due 2028150.0
 150.0
 5.625% due 2033335.0
 335.0
 5.70% due 2036300.0
 300.0
 3.65% due 2042250.0
 250.0
 4.25% due 2044250.0
 —
 6-7/8% due 2095100.0
 100.0
     
Note (secured, nonrecourse)4.81% effective rate due 20302.0
 2.0
     
Unamortized discount, net (21.5) (19.7)
Long-term debt due currently (250.0) (300.0)
Total Long-Term Debt 2,165.5
 2,167.3
     
Obligations Under Capital Leases (see Note J)2,712.5
 2,712.0
     
Total Long-Term Capitalization $8,321.2
 $8,316.5
     
Year Ended December 31      
(in millions) 2017 2016 2015
Operating revenues $3,711.7
 $3,792.8
 $3,854.1
       
Operating expenses      
Cost of sales 1,286.4
 1,292.1
 1,399.0
Other operation and maintenance 1,358.5
 1,430.2
 1,384.9
Depreciation and amortization 331.6
 325.4
 304.0
Property and revenue taxes 109.6
 115.6
 117.3
Total operating expenses 3,086.1
 3,163.3
 3,205.2
       
Operating income 625.6
 629.5
 648.9
       
Equity in earnings of transmission affiliate —
 55.5
 47.8
Other income, net 19.7
 9.1
 11.2
Interest expense 117.3
 117.6
 119.0
Other expense (97.6) (53.0) (60.0)
       
Income before income taxes 528.0
 576.5
 588.9
Income tax expense 191.2
 211.0
 212.0
Net income 336.8
 365.5
 376.9
       
Preferred stock dividend requirements 1.2
 1.2
 1.2
Net income attributed to common shareholder $335.6
 $364.3
 $375.7

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


2017 Form 10-K6851Wisconsin Electric Power Company
Table of Contents
2014 Form 10-K

C. CONSOLIDATED BALANCE SHEETS

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON EQUITY
        
 Common Other Paid Retained  
 Stock In Capital Earnings Total
 (Millions of Dollars)
        
Balance - December 31, 2011$332.9
 $941.9
 $1,902.3
 $3,177.1
Net income    367.3
 367.3
Cash dividends       
Common stock    (179.6) (179.6)
Preferred stock    (1.2) (1.2)
Stock-based compensation  2.8
   2.8
Tax benefit of exercised stock options allocated from Parent  —
   —
Balance - December 31, 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, 2013332.9
 965.1
 2,108.8
 3,406.8
Net income    377.9
 377.9
Cash dividends       
Common stock    (390.0) (390.0)
Preferred stock    (1.2) (1.2)
Stock-based compensation  3.5
   3.5
Tax benefit of exercised stock options allocated from Parent  15.8
   15.8
Balance - December 31, 2014$332.9
 $984.4
 $2,095.5
 $3,412.8
        
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
At December 31    
(in millions, except share and per share amounts) 2017 2016
Assets    
Current assets    
Cash and cash equivalents $12.3
 $15.4
Accounts receivable and unbilled revenues, net of reserves of $39.5 and $40.9, respectively 513.8
 503.2
Accounts receivable from related parties 109.1
 58.2
Materials, supplies, and inventories 250.7
 271.0
Prepayments 144.3
 138.0
Other 9.4
 24.6
Current assets 1,039.6
 1,010.4
     
Long-term assets    
Property, plant, and equipment, net of accumulated depreciation of $3,741.8 and $3,619.6, respectively 10,007.7
 9,832.3
Regulatory assets 1,984.9
 2,036.6
Equity investment in transmission affiliate —
 402.0
Other 89.4
 90.2
Long-term assets 12,082.0
 12,361.1
Total assets $13,121.6
 $13,371.5
     
Liabilities and Equity    
Current liabilities    
Short-term debt $210.9
 $159.0
Current portion of long-term debt 250.0
 —
Current portion of capital lease obligations 42.5
 28.5
Subsidiary note payable to WEC Energy Group —
 18.5
Accounts payable 329.3
 297.9
Accounts payable to related parties 131.5
 112.9
Accrued payroll and benefits 53.4
 51.8
Accrued taxes 58.2
 46.0
Other 111.8
 100.1
Current liabilities 1,187.6
 814.7
     
Long-term liabilities    
Long-term debt 2,412.3
 2,661.1
Capital lease obligations 2,823.8
 2,756.5
Deferred income taxes 1,155.5
 2,333.3
Regulatory liabilities 1,708.0
 853.9
Pension and OPEB obligations 143.2
 167.6
Other 276.9
 260.2
Long-term liabilities 8,519.7
 9,032.6
     
Commitments and contingencies (Note 19) 
 
     
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 802.7
 1,020.1
Retained earnings 2,248.3
 2,140.8
Common shareholder's equity 3,383.9
 3,493.8
     
Preferred stock 30.4
 30.4
Total liabilities and equity $13,121.6
 $13,371.5

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


2017 Form 10-K6952Wisconsin Electric Power Company
Table of Contents

D. CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31      
(in millions) 2017 2016 2015
Operating activities      
Net income $336.8
 $365.5
 $376.9
Reconciliation to cash provided by operating activities      
Depreciation and amortization 331.6
 325.4
 323.7
Deferred income taxes and investment tax credits, net 109.7
 206.2
 178.9
Contributions and payments related to pension and OPEB plans (8.3) (8.0) (107.6)
Equity income in transmission affiliate, net of distributions —
 (17.2) (4.9)
Payments for liabilities transferred to WBS (0.3) (116.0) —
Change in –      
Accounts receivable and unbilled revenues (64.9) (59.0) (2.9)
Materials, supplies, and inventories 20.3
 30.6
 18.8
Prepaid taxes 0.5
 39.4
 (2.8)
Other current assets (11.8) 9.3
 0.3
Accounts payable 45.8
 31.3
 (5.9)
Accrued taxes 12.8
 30.4
 (42.1)
Other current liabilities 12.2
 10.7
 (1.2)
Other, net (86.4) (0.2) (56.8)
Net cash provided by operating activities 698.0
 848.4
 674.4
       
Investing activities      
Capital expenditures (596.1) (469.5) (519.2)
Capital contributions to transmission affiliate —
 (16.1) (4.6)
Proceeds from the sale of assets 22.9
 31.7
 0.2
Proceeds from assets transferred to WBS —
 13.1
 —
Other, net 5.0
 4.0
 3.4
Net cash used in investing activities (568.2) (436.8) (520.2)
       
Financing activities      
Change in short-term debt 51.9
 15.0
 (162.8)
Repayment of subsidiary note to parent (18.5) (1.1) (2.9)
Issuance of long-term debt —
 —
 500.0
Retirement of long-term debt —
 —
 (250.0)
Equity contribution from parent 75.0
 —
 —
Payment of dividends to parent (240.0) (455.0) (240.0)
Payment of preferred stock dividends (1.2) (1.2) (1.2)
Other, net (0.1) 19.0
 5.8
Net cash used in financing activities (132.9) (423.3) (151.1)
       
Net change in cash and cash equivalents (3.1) (11.7) 3.1
Cash and cash equivalents at beginning of year 15.4
 27.1
 24.0
Cash and cash equivalents at end of year $12.3
 $15.4
 $27.1

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


20142017 Form 10-K53Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER COMPANY
Table of Contents

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, 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)
Tax benefit of exercised stock options allocated from parent —
 12.1
 —
 12.1
 —
 12.1
Stock-based compensation and other —
 3.2
 0.2
 3.4
 —
 3.4
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)
Tax benefit of exercised stock options allocated from parent —
 19.3
 —
 19.3
 —
 19.3
Stock-based compensation and other —
 1.1
 0.1
 1.2
 —
 1.2
Balance at December 31, 2016 $332.9
 $1,020.1
 $2,140.8
 $3,493.8
 $30.4
 $3,524.2
Net income —
 —
 336.8
 336.8
 —
 336.8
Dividends            
Common stock —
 —
 (240.0) (240.0) —
 (240.0)
Preferred stock —
 —
 (1.2) (1.2) —
 (1.2)
Cumulative effect adjustment from adoption of ASU 2016-09 —
 —
 11.9
 11.9
 —
 11.9
Equity contribution from parent —
 75.0
 —
 75.0
 —
 75.0
Transfer of net assets to UMERC —
 (61.1) —
 (61.1) —
 (61.1)
Transfer of ATC ownership interest and related taxes —
 (228.6) —
 (228.6) —
 (228.6)
Settlement of a short-term note receivable between Bostco and our parent company —
 (4.8) —
 (4.8) —
 (4.8)
Stock-based compensation and other —
 2.1
 —
 2.1
 —
 2.1
Balance at December 31, 2017 $332.9
 $802.7
 $2,248.3
 $3,383.9
 $30.4
 $3,414.3

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)
     2017 2016
Common shareholder's equity (see accompanying statement) 3,383.9
 3,493.8
Preferred stock (Note 9) 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
Obligations under capital leases     2,866.3
 2,785.0
Total     5,551.3
 5,472.0
Unamortized debt issuance costs     (3.2) (3.6)
Unamortized discount, net     (19.5) (22.3)
Total long-term debt and capital lease obligations, including current portion     5,528.6
 5,446.1
Current portion of long-term debt and capital lease obligations     (292.5) (28.5)
Total long-term debt and capital lease obligations     5,236.1
 5,417.6
Total long-term capitalization     $8,650.4
 $8,941.8

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


2017 Form 10-K55Wisconsin Electric Power Company
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G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


A -- NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:(a) Nature of OperationsWisconsin Electric Power Company (Wisconsin Electric, the Company,—On June 29, 2015, our us or we), a subsidiary ofparent company, Wisconsin Energy isCorporation, 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 which servicescompany that serves electric customers in Wisconsin and an iron ore mine owned by Tilden in the Upper Peninsula of Michigan, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. We consolidate our wholly-owned

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 assets previously held by us and the electric and natural gas distribution assets previously held by WPS, located in the Upper Peninsula of Michigan. The existing contract between us and Tilden will remain in place until a new power generation solution for the region is commercially operational, which is expected to occur in 2019.

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.

Through December 31, 2017, we had one wholly owned subsidiary, Bostco. At December 31, 2016, Bostco had total assets of $28.4 million$24.4 million. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 3, Dispositions, for more information. The financial statements include our accounts and $29.1 million asthe accounts of December 31, 2014our wholly owned subsidiary. The cost method of accounting is used for investments when we do not have significant influence over the operating and 2013, respectively.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.

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

The preparation(b) Basis of Presentation—We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America requires management toGAAP. We make estimates and assumptions that affect the reported amounts of certain assets and liabilities, andthe 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 couldmay differ from thosethese estimates.

Revenues:(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 revenues on the accrual basis and include estimated amounts for services renderedprovided but not billed.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 in Wisconsinset by the PSCW allow us to defer, for subsequent rate recovery or refund, any under-collectionunder- or over-collectionover-collections of actual fuel and purchased power costs that are outside of the symmetrical fuel cost tolerance, which the PSCW set at plus or minusexceed 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 approved fuel cost plan. The deferred under-collected amounts are subjectPSCW.

We received payments from MISO under an SSR agreement for our PIPP units through February 1, 2015. We recorded revenue for these payments to an excess revenues test.recover costs for operating and maintaining these units. See Note 21, Regulatory Environment, for more information.


2017 Form 10-K56Wisconsin Electric Power Company
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Our retailnatural gas utility rates include monthly adjustments which permit theincluded a one-for-one recovery or refund of actual purchasedmechanism for natural gas commodity costs. We defer any difference between actual natural 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.

AccountingOur 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 Transactions:   TheMarkets. 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 to Tilden located in the Upper Peninsula of Michigan, and provided electric service to other customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 4, Related Parties, and Note 21, 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, 2017. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2017.

(e) Materials, Supplies, and Inventories—Our inventory as of December 31 consisted of:
(in millions) 2017 2016
Materials and supplies $140.7
 $148.1
Fossil fuel 74.8
 91.1
Natural gas in storage 35.2
 31.8
Total $250.7
 $271.0

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.

Other IncomeRecovery or refund of regulatory assets and Deductions, Net:   Weliabilities 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 following itemsregulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in Other Incomethe reporting period the determination is made. See Note 5, Regulatory Assets and Deductions, netLiabilities, for the years ended December 31:more information.

Other Income and Deductions, net 2014 2013 2012
  (Millions of Dollars)
       
AFUDC - Equity $4.4
 $17.6
 $34.9
Gain on Property Sales 4.3
 0.8
 0.3
Other, net —
 (1.0) (2.9)
Total Other Income and Deductions, net $8.7
 $17.4
 $32.3

(g) Property, Plant, and Depreciation:Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overheadsoverhead, and capitalized interest. Utility property also includes AFUDC - Equity.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 other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

OurWe record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates are certifiedapproved by the PSCW and MPSC andthat include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.9%2.95%, 3.00%, and 3.01% in 2014, 20132017, 2016, and2012. 2015, respectively.


2017 Form 10-K7057Wisconsin Electric Power Company
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K


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.

We collectThird parties reimburse us for all or a portion of expenditures for certain capital projects. Such contributions in our rates amounts representing future removalaid of construction costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We recordare recorded as a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $571.2 million as of December 31, 2014reduction to property, plant, and $558.9 million as of December 31, 2013.equipment.

See Note 6, Property, Plant, and Equipment, for more information.

(h) Allowance Forfor Funds Used During Construction: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'shareholders' capital (AFUDC -– Equity) used for construction purposes. AFUDC -– Debt is recorded as a reduction of interest expense, and AFUDC -– Equity is recorded in Other Incomeother 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 2017, 2016, and Deductions, net.2015. Our average AFUDC wholesale rates were 5.94%, 2.73%, and 1.72% for 2017, 2016, and 2015, respectively.

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

  2014 2013 2012
  (Millions of Dollars)
       
AFUDC - Debt $1.8
 $7.4
 $14.5
AFUDC - Equity $4.4
 $17.6
 $34.9
(in millions) 2017 2016 2015
AFUDC – Debt $1.2
 $1.7
 $2.2
AFUDC – Equity $3.1
 $4.2
 $5.7

Materials, Supplies(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 Inventories:   Our inventorynormal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as of December 31 consists of:

Materials, Supplies and Inventories 2014 2013
  (Millions of Dollars)
     
Fossil Fuel $125.5
 $117.5
Materials and Supplies 145.0
 129.5
Natural Gas in Storage 50.0
 34.0
Total $320.5
 $281.0

Substantially all fossil fuel, materials and supplies and natural gas in storage inventories are recorded usinglong as the weighted-average costfair value can be reasonably estimated, even if the timing or method of accounting.

Regulatory Accounting:settling the obligation is unknown. 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,associated retirement costs are deferredcapitalized 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 amountpart of the related long-lived asset. We accrete the liability to its present value each periodasset and depreciate the capitalized costare depreciated over the useful life of the related asset. AtThe ARO liabilities are accreted each period using the endcredit-adjusted risk-free interest rates associated with the expected settlement dates of the asset's useful life, we settleAROs. These rates are determined when the obligation for its recordedobligations 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 incur a gain or loss. As it relatesdecrease to our regulated operations, we apply regulatory accounting guidancethe carrying amount of the liability and the associated retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover legal AROsan ARO in rates and when we would recognize thesethe associated retirement costs. For further information, seeSee Note E.7, Asset Retirement Obligations, for more information.

Derivative Financial Instruments:(j) Asset Impairment—We have derivative physicalperiodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and financial instruments which we report at fair value. For further information, see Note L.judgments by management. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future.

When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets applicable criteria to be considered probable of abandonment, we assess the likelihood of recovery of the remaining carrying value of that generating unit at the end of each reporting period. If it becomes probable that regulators will not allow full recovery as well as a return on the remaining net book value of the abandoned generating unit, an impairment charge may be required. An impairment charge would be recorded if the remaining carrying value of the abandoned generating unit is greater than the present value of the amount expected to be recovered from ratepayers. See Note 6, Property, Plant, and Equipment, for more information.

(k) Stock-Based Compensation—Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives 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.

2017 Form 10-K7158Wisconsin Electric Power Company
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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.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded an $11.9 million cumulative-effect adjustment to increase retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable.

ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.

As we did not record any excess tax benefits in 2017, adoption of ASU 2016-09 had no impact on our financial statements other than the cumulative-effect adjustment discussed above.

Stock Options

Our employees are granted WEC Energy Group non-qualified stock options that generally 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 the 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 weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models:
  2017
2016
2015
Stock options granted * 80,770
 92,880
 495,550
       
Estimated weighted-average fair value per stock option $7.12
 $4.92
 $5.29
       
Assumptions used to value the options:      
Risk-free interest rate 0.7% – 2.5%
 0.5% – 2.2%
 0.1% – 2.1%
Dividend yield 3.5% 4.0% 3.7%
Expected volatility 19.0% 18.0% 18.0%
Expected life (years) 6.2
 5.8
 5.8

*
Effective January 1, 2016, certain employees were transferred into WBS.See Note 4, Related Parties, for more information.
The risk-free interest rate was 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 dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience.

Restricted Shares

WEC Energy Group restricted shares granted to our employees have a three-year vesting period with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)20142017 Form 10-K59Wisconsin Electric Power Company

Cash and Cash Equivalents:Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.
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Margin Accounts:   Cash deposited in brokerage accounts for margin requirements is recorded in Other Current Assets on our Consolidated Balance Sheets.Performance Units

Restrictions:Various financing arrangementsOfficers and regulatory requirements impose certain restrictionsother 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 our abilityWEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to transfer fundsthe 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 Wisconsin Energythe terms of the plan. Performance units granted on or after January 1, 2016 also accrue forfeitable dividend equivalents 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.additional performance units.

Impairment or DisposalAll grants of Long Lived Assets:   We carry propertyperformance units are settled in cash and equipment related to businesses heldare accounted for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2014, we had no assets classified as Held for Sale. Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds theliability awards accordingly. The fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sumperformance units reflects our estimate of the undiscounted cash flowsfinal expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are recorded over the three-year performance period.

Investments:   We accountSee Note 8, Common Equity, for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 23.0% in ATC as of December 31, 2014 and 2013. We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note P.on WEC Energy Group's stock-based compensation plans.

(l) Income Taxes:   Taxes—We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

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

the assets. We are included in Wisconsin Energy'sWEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WisconsinWEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. For further information on income taxes, seeSee 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.12, Income Taxes, for more information.

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

We collect sales
(m) 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 use taxes from our customersthe 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 remit these taxesvolume to governmental authorities. These taxes are recorded in our Consolidated Income Statementsprovide pricing information on a netan ongoing 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.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.

Wisconsin Energy estimatesLevel 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 of stock options using the binomialmeasurement. We use a mid-market pricing model. Historically, all stock options have been granted with an exerciseconvention (the mid-point price equal to the fair market value of the common stock on the date of grantbetween bid and expire no later than 10 years from the grant date. Excess tax benefits are reportedask prices) as a financing cash inflow. In addition, Wisconsin Energy reports unearned stock-based compensation associated with non-vestedpractical 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

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


restricted stock and performance awards within other paidquoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in capitalLevel 2. Certain derivatives are categorized in its Consolidated StatementsLevel 3 due to the significance of Common Equity. For a discussionunobservable or internally-developed inputs.

We recognize transfers between levels of the impacts to our Consolidated Financial Statements, see Note H.fair value hierarchy 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 debt, the carrying amount of each such item approximates fair value. The fair value of each Wisconsin Energy option was calculatedour preferred stock is estimated based on the quoted market value for the same issue, or by using a binomial option pricing model usingdividend discount model. The fair value of our long-term debt is estimated based upon the following weighted-average assumptions: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.

 2014 2013 2012
Risk-free interest rate0.1% - 3.0% 0.1% - 1.9% 0.1% - 2.0%
Dividend yield3.8% 3.7% 3.9%
Expected volatility18.0% 18.0% 19.0%
Expected life (years)5.8 5.9 5.9
Expected forfeiture rate2.0% 2.0% 2.0%
Weighted-average fair value     
of stock options granted$4.18 $3.45 $3.34
See Note 13, Fair Value Measurements, for more information.

Treasury Grant:   (n) Derivative InstrumentsIn December 2013, we filed an application—We use derivatives as part of our risk management program to manage the risks associated with the United States Treasuryprice volatility of purchased power, generation, and natural gas costs for a Section 1603 renewable energy grant related to the constructionbenefit of our biomass facility in Rothschild, Wisconsin. The PSCW anticipatedcustomers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the recognition of this grant as income when it set rates for the two years beginning January 1, 2013. We provided bill credits to our customers in 2013 and 2014. For the years ended December 31, 2014 and 2013, $17.4 million and $48.0 million, respectively, was recognized as income, which reflects the amount that was returned to customers in the form of bill credits during the year. The accounting reflects the regulatory treatment of the grant.PSCW.

In June 2014, we received approximately $76.2 million related to the Treasury Grant. The PSCW approved escrow accountingWe record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the Treasury Grantnormal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the proceedstreatment 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 that exceededis reflected in other current liabilities. See Note 14, Derivative Instruments, for more information.

(o) Employee Benefits—The costs of pension and OPEB plans are expensed over the amounts originally includedperiods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates are being returned to customers in the form of bill credits.


B -- RECENT ACCOUNTING PRONOUNCEMENTS

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


C -- REGULATORY ASSETS AND LIABILITIES(p) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.

Our primary regulator,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 PSCW, considersyear, 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 regulatory assetsbalance sheets.
(q) 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 7, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 19, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

We record environmental remediation liabilities in two categories, escrowedwhen site assessments indicate remediation is probable and deferred. In escrow accounting we expensecan reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that are included in rates. If actual costs exceed or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon orders or correspondence with our regulators. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2014, we had $11.7 million of regulatory assets not earning a return and $115.1 million of regulatory assets earning a return based on short-term interest rates.

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


2017 Form 10-K7361Wisconsin Electric Power Company
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

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.

OurWe 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 PSCW'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, and liabilities as of December 31 consist of:appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

  2014 2013
  (Millions of Dollars)
Regulatory Assets    
Deferred plant related -- capital leases $603.0
 $512.5
Deferred unrecognized pension costs 482.8
 393.0
Deferred income tax related 171.5
 165.8
Escrowed electric transmission costs 146.0
 126.8
Other, net 223.6
 172.2
Total regulatory assets $1,626.9
 $1,370.3
     
Regulatory Liabilities    
Deferred cost of removal obligations $571.2
 $558.9
Other, net 44.7
 75.3
Total regulatory liabilities $615.9
 $634.2
NOTE 2—ACQUISITIONS

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 recoveredParent Company's Acquisition of Natural Gas Storage Facilities in rates and the expense that would result from the amortization of the leased asset and the imputed interest expense.


D -- PROPOSED ACQUISITION OF INTEGRYS BY WISCONSIN ENERGYMichigan

On June 22, 2014,30, 2017, our parent company Wisconsin Energy,completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that will provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we entered into ana long-term service agreement and planwith a wholly owned subsidiary of merger (Merger Agreement) underBluewater to take the allocated storage, which it will acquirewas then approved by the PSCW in November 2017. See Note 21, Regulatory Environment, for more information.

Parent Company's Acquisition of Integrys Energy Group (Integrys). Integrys' shareholders will receive 1.128

On June 29, 2015, our parent company acquired 100% of the outstanding common shares of Wisconsin Energy common stockIntegrys and $18.58 in cash per Integrys share of common stock. We expect Wisconsin Energychanged its name to finance the acquisition through the issuance of approximately 91 million shares of Wisconsin Energy common stock to Integrys shareholders and through the issuance of approximately $1.5 billion of debt. Wisconsin Energy will also assume all of Integrys' outstanding debt. The combined company will be named WEC Energy Group, Inc. Integrys is a provider of regulated natural gas and electricity, as well as nonregulated renewable energy.

The acquisition iswas subject to several conditions, including, among others, approvalthe approvals of the shareholders of both Wisconsin Energy and Integrys, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), and the receipt of approvals from various government agencies, including the FERC, Federal Communications Commission,PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW Illinois Commerce Commission, MPSCorder 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 Minnesota Public Utilities Commission. The status of these matters as ofwill reduce our transmission escrow. All utility earnings above the first 50 basis points will be solely used to reduce the transmission escrow. For the years ended December 31, 2014 is as follows:2017 and 2016, we recorded $0.1 million and $21.1 million of expense related to this earnings sharing mechanism, respectively.
On August 6, 2014,
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 applications for approvala joint integrated resource plan with the PSCW Illinois Commerce Commission, MPSCfor our combined loads, which indicated that no new generation was needed at the time.

In 2015, we recorded $6.6 million of severance expense that resulted from employee reductions related to the post-acquisition integration. The severance expense was recorded in our utility segment and Minnesota Public Utilities Commission.
On August 15, 2014, Wisconsin Energy filed an application withis included in the FERC.other operation and maintenance line item on the income statements. Severance expense incurred after 2015 was not significant. Severance payments made during 2017 were not significant. Severance payments of $4.6 million and $1.2 million were made during 2016 and 2015, respectively. The initial public comment period closedseverance accrual on October 17, 2014. Wisconsin Energy subsequently submitted additional informationour balance sheets at December 31, 2017 and 2016 related to respond to FERC questions on December 18, 2014. That comment period is now closed.
On September 24, 2014, Wisconsin Energy submitted its HSR Act filings, and on October 24, 2014, the United States Department of Justice closed its review of the transaction with no further action required. In addition, on October 24, 2014, the Federal Trade Commission granted early termination of the 30-day waiting period required by the HSR Act.
On November 21, 2014, the shareholders of Wisconsin Energy voted to approve the issuance of common stock as contemplated by the Merger Agreement, as well as to amend the restated articles of incorporation to change the name of Wisconsin Energy from Wisconsin Energy Corporation to WEC Energy Group, Inc. The shareholdersacquisition of Integrys approved the adoption of the Merger Agreement at its shareholder meeting held on November 21, 2014.was not significant.

Wisconsin Energy anticipates
NOTE 3—DISPOSITIONS

Utility Segment

Sale of Milwaukee County Power Plant

In April 2016, we sold the transaction closingMCPP 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 second half of 2015.sale were not material and, therefore, were not presented as




2017 Form 10-K7462Wisconsin Electric Power Company
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

E -- ASSET RETIREMENT OBLIGATIONS

AROsheld 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 beena major effect on our operations and financial results.

Other Segment

Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for asbestos abatement at certain generation and substation facilities, and for obligationssale. The results of operations associated with these assets remained in continuing operations through the removal and dismantlement of generation facilities. AROs are recorded in other long-term liabilities onsale date as the Consolidated Balance Sheets. The following table presents the changesale did not represent a shift in our AROs during 2014corporate strategy and 2013:did not have a major effect on our operations and financial results.

  2014 2013
  (Millions of Dollars)
     
Balance as of January 1 $39.4
 $41.5
Liabilities Settled (1.1) (4.3)
Accretion 2.2
 2.2
Balance as of December 31 $40.5
 $39.4
NOTE 4—RELATED PARTIES


F -- VARIABLE INTEREST ENTITIES

The primary beneficiary of a variable interest entity must consolidate theWe routinely enter into transactions with related assetsparties, including WEC Energy Group, its other subsidiaries, ATC, and liabilities. Certain disclosures are required by sponsors, significant interest holders in variable interest entities and potential variable interestother affiliated entities.

We assess our relationships with potential variable interest entities such as our coal suppliers, natural gas suppliers, coalprovide and gas transporters,receive services, property, and other counterparties in power purchase agreementsitems of value to and joint ventures. In making this assessment, we consider the potential thatfrom 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' activitiesparent, WEC Energy Group, and other factors.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.

We have identified a purchased power agreement which represents a variable interest. This agreement is for Services under the Non-WBS236 MWAIA 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 firm capacity from a gas-fired cogeneration facility and we account for it as a capital lease. The agreement includes no minimum energy requirements overcost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary were priced at the remaining termlesser of approximately eight years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equitycost or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.fair market value. All services provided by any regulated or nonregulated subsidiary to WBS were priced at cost.

We have approximately $174.0WBSprovided 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.

A new AIA took effect January 1, 2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. All of the applicable state commissions approved modifications to the new AIA to incorporate WEC Energy Group's acquisition of Bluewater. See Note 2, Acquisitions, for more information on the acquisition.

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.

Bostco, our consolidated subsidiary, had a note payable to our parent company, WEC Energy Group. The balance of this note payable was $18.5 million at December 31, 2016, which was paid off in the first half of 2017.

In connection with the sale of Bostco’s remaining real estate holdings, Wispark, a subsidiary of WEC Energy Group, provided $7.0 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under contracts considered variable interests in 2014, 2013 and 2012 were $53.0 million, $50.3 million and $45.8 million, respectively. Our maximum exposure to loss is limitedfinancing to the capacity payments underbuyer and established a corresponding note receivable. Bostco had a $7.0 million related party receivable from Wispark that was paid in April 2017. See Note 3, Dispositions, for more information on the contract.real estate sale.


G -- INCOME TAXES

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

Income Taxes 2014 2013 2012
  (Millions of Dollars)
       
Current tax expense (benefit) $31.2
 $7.3
 $(1.4)
Deferred income taxes, net 192.5
 194.7
 195.2
Investment tax credit, net (1.1) (1.1) (1.1)
Total Income Tax Expense $222.6
 $200.9
 $192.7


2017 Form 10-K7563Wisconsin Electric Power Company
Table of Contents

Effective January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016, to another subsidiary of WEC Energy Group. In addition, we transferred $186.8 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss.

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. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs.

Our balance sheets included the following receivables and payables related to transactions entered into with ATC:
(in millions) 2017 2016
Accounts receivable    
Services provided to ATC $0.8
 $1.1
Accounts payable    
Services received from ATC 22.2
 20.0

The following table shows activity associated with our related party transactions for the years ended December 31:
(in millions) 2017 2016 2015
Lease agreements  
  
  
Lease payments to We Power (1)
 $420.5
 $412.2
 $410.5
CWIP billed to We Power 57.3
 37.9
 58.8
Transactions with WBS (2)
      
Billings to WBS (3)
 255.7
 213.8
 11.1
Billings from WBS (4)
 215.4
 310.6
 1.3
Transactions with WPS (2)
      
Natural gas purchases from WPS 1.6
 1.9
 0.4
Billings to WPS 28.2
 9.0
 13.4
Billings from WPS 4.5
 4.2
 4.9
Transactions with WG      
Natural gas purchases from WG 5.3
 5.3
 5.3
Billings to WG 64.0
 60.6
 79.4
Billings from WG 23.1
 21.5
 23.5
Transactions with UMERC (5)
      
Electric sales to UMERC 30.8
 —
 —
Billings to UMERC (2)
 125.5
 —
 —
Transactions with Bluewater (6)
      
Storage service fees 2.7
 —
 —
Transactions with ATC      
Charges to ATC for services and construction 10.9
 10.0
 9.7
Charges from ATC for network transmission services 241.4
 247.8
 238.5
Refund from ATC per FERC ROE order (19.4) —
 —

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)
(1)
2014 Form 10-KWe make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2.

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

  2014 2013 2012
    Effective   Effective   Effective
Income Tax Expense Amount Tax Rate Amount Tax Rate Amount Tax Rate
  (Millions of Dollars)
             
Expected tax at statutory federal tax rates $209.8
 35.0 % $196.3
 35.0 % $195.6
 35.0 %
State income taxes net of federal tax benefit 33.0
 5.5 % 31.7
 5.6 % 28.8
 5.1 %
Production tax credits (17.4) (2.9)% (16.7) (3.0)% (15.9) (2.8)%
Treasury Grant (3.8) (0.6)% (7.4) (1.3)% —
 — %
AFUDC - Equity (1.5) (0.2)% (6.1) (1.1)% (12.2) (2.2)%
Investment tax credit restored (1.1) (0.2)% (1.1) (0.2)% (1.1) (0.2)%
Domestic production activities deduction —
 — % —
 — % (12.6) (2.3)%
Other, net 3.6
 0.5 % 4.2
 0.7 % 10.1
 1.8 %
Total Income Tax Expense $222.6
 37.1 % $200.9
 35.7 % $192.7
 34.4 %
(2)
Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs.

The components of deferred income taxes classified as net current assets and net long-term liabilities as of December 31 are as follows:
(3)
Includes $1.2 million, for the transfer of certain benefit-related liabilities from WBS for the year ended December 31, 2017. For the year ended December 31, 2016, includes $13.1 million for the transfer of certain software assets to WBS. There were no transfers of assets to WBS during the year ended December 31, 2017, and there were no transfers of liabilities from WBS for the year ended December 31, 2016.

(4)
For the year ended December 31, 2017 and 2016, includes $1.5 million and $116.0 million, respectively, for the transfer of certain benefit-related liabilities to WBS.

(5)
UMERC became operational effective January 1, 2017. See below for more information.

(6)
The acquisition of Bluewater was completed on June 30, 2017. See below for more information.

Deferred Tax Assets 2014 2013
  (Millions of Dollars)
Current    
Future federal tax benefits $56.0
 $113.1
Uncollectible account expense 15.6
 17.2
Employee benefits and compensation 11.6
 11.7
Recoverable gas costs 1.0
 0.5
Other 2.3
 3.3
Total Current Deferred Tax Assets 86.5
 145.8
     
Non-current    
Deferred revenues 221.3
 237.0
Employee benefits and compensation 92.1
 92.4
Construction advances 15.5
 15.0
Emission Allowances 0.1
 —
Other 31.7
 42.2
Total Non-Current Deferred Tax Assets 360.7
 386.6
Total Deferred Tax Assets $447.2
 $532.4

2017 Form 10-K7664Wisconsin Electric Power Company
Table of Contents


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. See Note 21, Regulatory Environment, for more information. 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 book value of net assets, including the related deferred income tax liabilities, transferred to UMERC from us as of January 1, 2017, was $61.1 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WPS.

NOTE 5—REGULATORY ASSETS AND LIABILITIES

We recorded a $1,065 million change in our deferred taxes due to the enactment of the Tax Legislation, which resulted in both an increase to income tax related regulatory liabilities as well as a decrease to certain existing income tax related regulatory assets represented in Income tax related items in the table below. The $1,065 million change in our deferred taxes represents our estimate of the tax benefit that will be returned to ratepayers through future refunds, bill credits, or reductions in other regulatory assets. See Note 12, Income Taxes, for more information on the Tax Legislation.

The following regulatory assets were reflected on our balance sheets as of December 31:
(in millions) 2017 2016 See Note
Regulatory assets (1) (2)
      
Plant related – capital leases $801.3
 $724.8
 11
Unrecognized pension and OPEB costs (3)
 484.4
 520.3
 15
SSR 298.9
 188.1
 21
Electric transmission costs 220.7
 231.9
 21
We Power generation (4)
 71.3
 54.1
  
AROs 41.4
 39.7
 7
Environmental remediation costs (5)
 30.4
 29.9
 19
Energy efficiency programs (6)
 28.2
 38.5
  
Income tax related items —
 200.8
 12
Other, net 8.3
 8.5
  
Total regulatory assets $1,984.9
 $2,036.6
  

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)
(1)
2014 Form 10-KBased 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, 2017, we had $11.4 million of regulatory assets not earning a return and $254.0 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. The other regulatory assets in the table either earn a return or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.
(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 amounts recoverable from customers related to our costs of the generating units leased from We Power, including subsequent capital additions. See Note 11, Long-Term Debt and Capital Lease Obligations, for more information on the Tax Legislation impacts on the lease payments.

(5)
As of December 31, 2017, we had not yet made cash expenditures for $18.5 million of these environmental remediation costs.

(6)
Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards.
Deferred Tax Liabilities 2014 2013
  (Millions of Dollars)
Current    
Prepaid items $39.8
 $70.0
Total Current Deferred Tax Liabilities 39.8
 70.0
     
Non-current    
Property-related 1,942.2
 1,820.9
Investment in transmission affiliate 164.1
 147.8
Employee benefits and compensation 131.2
 135.0
Deferred transmission costs 58.5
 50.8
Other 28.6
 26.6
Total Non-current Deferred Tax Liabilities 2,324.6
 2,181.1
Total Deferred Tax Liabilities $2,364.4
 $2,251.1
     
Consolidated Balance Sheet Presentation 2014 2013
Current Deferred Tax Asset $46.7
 $75.8
Non-Current Deferred Tax Liability $1,963.9
 $1,794.5


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

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

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

 2014 2013
 (Millions of Dollars)
    
Balance as of January 1$8.4
 $10.8
Reductions for tax positions of prior years(1.2) (2.4)
Balance as of December 31$7.2
 $8.4

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

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

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


2017 Form 10-K7765Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

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


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 toregulatory liabilities were reflected on our employees during the years endedbalance sheets as of December 31:
(in millions) 2017 2016 See Note
Regulatory liabilities      
2017 Tax Legislation impact and income tax related $849.1
 $—
 12
Removal costs (1)
 730.0
 722.9
  
Mines deferral (2)
 95.1
 70.2
  
Other, net 46.9
 71.0
  
Total regulatory liabilities $1,721.1
 $864.1
  
       
Balance Sheet Presentation      
Current liabilities $13.1
 $10.2
  
Regulatory liabilities 1,708.0
 853.9
  
Total regulatory liabilities $1,721.1
 $864.1
  

(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 6—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31:
  2014 2013 2012
  (Millions of Dollars)
       
Performance units $12.7
 $11.9
 $14.2
Stock options 3.6
 3.8
 2.6
Restricted stock 2.1
 1.6
 2.0
Share-based compensation expense $18.4
 $17.3
 $18.8
       
Related Tax Benefit $7.4
 $6.9
 $7.5
(in millions) 2017 2016
Utility property, plant, and equipment (1)
 $9,870.7
 $11,232.9
Less: Accumulated depreciation 2,970.3
 3,606.9
Net 6,900.4
 7,626.0
CWIP 159.5
 111.5
Plant to be retired, net 872.7
 —
Net utility property, plant, and equipment 7,932.6
 7,737.5
     
Property under capital leases 3,009.1
 2,898.0
Less: Accumulated amortization 945.9
 837.8
Net leased facilities 2,063.2
 2,060.2
     
Non-utility and other property, plant, and equipment 11.9
 46.4
Less: Accumulated depreciation —
 12.7
Net (2)
 11.9
 33.7
CWIP —
 0.9
Net non-utility and other property, plant, and equipment 11.9
 34.6
     
Total property, plant, and equipment $10,007.7
 $9,832.3

(1)
Effective 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 net book value of the property, plant, and equipment we transferred to UMERC was $61.1 million. See Note 4, Related Parties, for more information.

(2)
In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space.

Utility Segment Plant to be Retired

Stock Options:We have evaluated future plans for our older and less efficient fossil fuel generating units and have announced our plans for the retirement of the plants identified below. The exercise pricenet book value of a Wisconsin Energy stock option under the plan isthese plants was classified as plant to be no less than 100% of the common stock's fair market valueretired within property, plant, and equipment on the grant date and options may not be exercised within six months of the grant date exceptour balance sheet at December 31, 2017. In addition, severance expense in the eventamount of a change$25.8 million was recorded within the utility segment 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.2017 related to these announced plant retirements.

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

      Weighted-Average  
    Weighted- Remaining Aggregate
  Number of Average Contractual Life Intrinsic Value
Stock Options Options Exercise Price (Years) (Millions)
Outstanding as of January 1, 2014 7,688,843
 $26.92
    
Granted 864,860
 $41.03
    
Exercised (2,086,231) $22.95
    
Forfeited (17,195) $37.42
    
Outstanding as of December 31, 2014 6,450,277
 $30.07
 5.7 $146.2
         
Exercisable as of December 31, 2014 3,682,442
 $24.14
 3.9 $105.3

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


2017 Form 10-K7866Wisconsin Electric Power Company
Table of Contents


Pleasant Prairie Power Plant

As a result of a MISO ruling in December 2017, Pleasant Prairie must be shut down no later than April 10, 2018. Because we had an obligation at December 31, 2017 to shut down the Pleasant Prairie plant in April 2018, retirement of the plant was probable at December 31, 2017. The net book value of this generating unit was $681.3 million at December 31, 2017. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. This unit is included in rate base, and we continue to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. The physical dismantlement of the plant will not occur immediately.  It may take several years to finalize long-term plans for the site. See Note 19, Commitments and Contingencies, for more information.

Presque Isle Power Plant

In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. Upon receiving this approval, retirement of the PIPP generating units became probable. The new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. The net book value of these units was $191.4 million at December 31, 2017. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. The net book value of these assets was transferred from plant in service to plant to be retired. See Note 19, Commitments and Contingencies, for more information.

NOTE 7—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 rate-making practices for retirement costs authorized by the applicable regulators. On our balance sheets, AROs are recorded within other long-term liabilities.

The following table shows changes to our AROs during the years ended December 31:
(in millions) 2017 2016 2015 
Balance as of January 1 $61.5
 $58.7
 $40.5
 
Accretion 3.2
 3.0
 2.3
 
Additions 5.5
(1) 
—
 15.9
(2) 
Liabilities settled (1.9) (0.2) —
 
Balance as of December 31 $68.3
 $61.5
 $58.7
 

(1)
During 2017, an ARO was recorded related to the removal and dismantlement of the Rothschild Biomass Plant.

(2)
During 2015, an ARO was recorded for the fly-ash landfills located at our generation facilities.

NOTE 8—COMMON EQUITY

Stock-Based Compensation Plans

The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31:
(in millions) 2017 2016 2015
Stock options $1.3
 $1.8
 $3.2
Restricted stock 0.8
 1.8
 2.1
Performance units 9.9
 3.9
 7.5
Stock-based compensation expense $12.0
 $7.5
 $12.8
Related tax benefit $4.8
 $3.0
 $5.1


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)20142017 Form 10-K67Wisconsin Electric Power Company
Table of Contents

In JanuaryStock-based compensation costs capitalized during 2017, 2016, and 2015 were not significant.

Stock Options

The following is a summary of our employees' WEC Energy Group stock option activity during 2017:
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, 2017 1,285,806
 $33.41
    
Granted 80,770
 $58.31
    
Exercised (300,064) $25.54
    
Transferred 129,635
 $35.48
    
Outstanding as of December 31, 2017 1,196,147
 $37.29
 4.6 $34.9
Exercisable as of December 31, 2017 971,547
 $33.43
 3.8 $32.1

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, 2017. This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2017, 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, 2017, 2016, and 2015 was $11.2 million, $14.1 million, and $34.6 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $7.7 million, $12.1 million, and $29.2 million during the years ended December 31, 2017, 2016, and 2015, respectively. The actual tax benefit from option exercises for the same periods was approximately $4.5 million, $5.6 million, and $14.0 million, respectively.

As of December 31, 2017, we expected to recognize approximately $0.9 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.7 years on a weighted-average basis.

During the first quarter of 2018, the Compensation Committee of the Board of Directors of Wisconsinawarded 81,730 non-qualified WEC Energy (Compensation Committee) awarded 495,550 Wisconsin Energy non-qualifiedGroup stock options with an exercise price of $52.895$66.02 and a weighted-average grant date fair value of $7.26 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 2017:
Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value
Outstanding as of January 1, 2017 16,261
 $50.39
Granted 8,001
 $58.10
Released (8,018) $48.78
Transferred (379) $57.77
Forfeited (582) $53.83
Outstanding as of December 31, 2017 15,283
 $54.96

The intrinsic value of WisconsinWEC Energy options exercised duringGroup restricted stock held by our employees that was released was $0.5 million, $0.4 million, and $2.7 million for the years ended December 31, 2014, 20132017, 2016, and 2012 was $47.5 million, $41.2 million and $42.9 million, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $47.9 million, $45.5 million and $45.4 million during the years ended December 31, 2014, 2013 and 2012,2015, respectively. The actual tax benefit realized for the tax deductions from option exercisesreleased restricted shares for the same periodsyears was approximately $18.8$0.2 million,, $16.6 $0.2 million, and zero,$1.1 million, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding asAs of December 31, 2014:

  Options Outstanding Options Exercisable
    Weighted-Average   Weighted-Average
      Remaining     Remaining
  Number of Exercise Contractual Number of Exercise Contractual
Range of Exercise Prices Options Price  Life (Years) Options Price  Life (Years)
$17.10  to  $21.11 1,411,769
 $20.88 3.6 1,411,769
 $20.88 3.6
$23.88  to  $29.35 2,038,633
 $25.07 3.7 2,038,633
 $25.07 3.7
$34.88  to  $41.03 2,999,875
 $37.79 8.0 232,040
 $35.86 7.4
             
  6,450,277
 $30.07 5.7 3,682,442
 $24.14 3.9

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

  Number of 
Weighted-
Average
Non-Vested Stock Options Options  Fair Value
     
Non-Vested as of January 1, 2014 2,289,400
 $3.38
Granted 864,860
 $4.18
Vested (369,230) $3.26
Forfeited (17,195) $3.56
Non-Vested as of December 31, 2014 2,767,835
 $3.65

As2017, we expected to recognize approximately $1.2 million of December 31, 2014, totalunrecognized compensation costscost related to non-vested WisconsinWEC Energy Group restricted stock options held by our employees and not yet recognized was approximately $2.0 million, which is expected to be recognized over the next 19 months1.7 years on a weighted-average basis.

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

  Number of 
Weighted-
Average
Market
Restricted Shares Shares Price
Outstanding as of January 1, 2014 98,226
  
Granted 51,873
 $40.98
Released (46,228) $34.31
Forfeited (3,214) $38.47
Outstanding as of December 31, 2014 100,657
  

79Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

In January 2015,2018, the Compensation Committee awarded 43,2127,518 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. TheseThe grant date fair value of 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.was $64.99 per share.

Wisconsin Energy records the market value
2017 Form 10-K68Wisconsin Electric Power Company
Table of the restricted stock awards on the date of grant. We then amortize our share of allocated expense over the vesting period of the awards. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was $2.3 million, $2.8 million and $2.2 million for the years ended December 31, 2014, 2013 and 2012, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.9 million, $1.1 million and zero, respectively.Contents

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

Performance Units:   In January 2014, 2013During 2017, 2016, and 2012,2015, the Compensation Committee awarded 224,735, 230,24534,765; 35,700; and 333,685 Wisconsin187,450 WEC Energy Group performance units, respectively, to our officers and other key employees under the WisconsinWEC Energy Group Performance Unit Plan. Under

In 2016, we transferred 573,499 performance units to WBS in connection with the grants, the ultimate number of units that will be awarded is dependent upon the achievementtransfer 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 expectedemployees. See Note 4, Related Parties, for more information.

Performance units with an intrinsic value of the awards. Performance units earned as of December 31, 2014, 2013$1.4 million, $3.4 million, and 2012 vested and$11.6 million were settled during the first quarter of2017, 2016, and 2015, 2014 and 2013, and had a total intrinsic value of $11.6 million, $13.1 million and $17.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlementdistribution of performance units for the same years was approximately $0.4 million, $0.5 million, and $4.2 million, $4.7respectively.

At December 31, 2017, we had 96,577 performance units outstanding, including dividend equivalents. A liability of $4.9 million and $6.2 million, respectively. was recorded on our balance sheet at December 31, 2017 related to these outstanding units. As of December 31, 2014, total2017, we expected to recognize approximately $3.6 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units not yet recognized was approximately $10.9 million, which is expected to be recognized over the next 20 months1.4 years on a weighted-average basis.

During the first quarter of 2018, performance units held by our employees with an intrinsic value of $1.8 million were settled. The actual tax benefit from the distribution of these awards was $0.4 million. In January 2015,2018, the Compensation Committee also awarded 187,45032,650 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restrictions:Restrictions

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. In addition, under Wisconsin law we are prohibitedprohibits us from loaning funds, either directlymaking loans to or indirectly, to Wisconsin Energy.guaranteeing obligations of WEC Energy Group or its subsidiaries.

We are required to maintain a capital structure that differs from GAAP as it reflects regulatory adjustments. Both the 2013 PSCWIn accordance with our most recent rate case order, and the 2015 PSCW rate case order require us to maintain awe may not pay 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 thatforecasted 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 toat the end of the year provided that our average common equity ratio does not fall below the authorized level of common equity.level.

We may not pay common dividends to WisconsinWEC 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 K10, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to our bank back-up credit facility.short-term debt obligations.

WeAs of December 31, 2017, our restricted retained earnings totaled $2.2 billion.

Except for the restrictions described above and subject to applicable law, we do not believe that these restrictions will materially affect our operations or limithave any other significant dividend payments in the foreseeable future.restrictions.

NOTE 9—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2017 and 2016:
(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


80Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)20142017 Form 10-K

I -- PREFERRED STOCK

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

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


J -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

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

 (Millions of Dollars)
  
2015$250.0
2016—
2017—
2018250.0
2019250.0
Thereafter1,687.0
Total$2,437.0

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

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147.0 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2014 and 2013, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt or included on our Consolidated Statements of Capitalization because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Obligations Under Capital Leases

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

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

8169Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

expire. We recorded the leased facility and corresponding obligation under the capital lease at the estimated fair valueTable 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.Contents

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

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

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

  2014 2013 2012
  (Millions of Dollars)
       
Long-term power purchase commitment $34.9
 $33.7
 $32.5
PWGS  99.2
 99.1
 99.0
Oak Creek Expansion 277.8
 274.9
 269.3
Total $411.9
 $407.7
 $400.8
NOTE 10—SHORT-TERM DEBT AND LINES OF CREDIT

The following table summarizesshows our capitalized leased facilitiesshort-term borrowings and their corresponding weighted-average interest rates as of December 31:
Capital Lease Assets 2014 2013
  (Millions of Dollars)
     
Long-term Power Purchase Commitment    
Under capital lease $140.3
 $140.3
Accumulated amortization (98.3) (92.5)
Total Long-term Power Purchase Commitment $42.0
 $47.8
     
PWGS     
Under capital lease $682.7
 $681.5
Accumulated amortization (217.6) (190.1)
Total PWGS  $465.1
 $491.4
     
Oak Creek Expansion    
Under capital lease $2,025.6
 $1,991.1
Accumulated amortization (317.7) (251.3)
Total Oak Creek $1,707.9
 $1,739.8
     
Total Leased Facilities $2,215.0
 $2,279.0

82Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

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

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


K -- SHORT-TERM DEBT
(in millions, except percentages) 2017 2016
Commercial paper    
Amount outstanding at December 31 $210.9
 $159.0
Average interest rate on amounts outstanding at December 31 1.81% 0.87%

Our average amount of commercial paper balance and the correspondingborrowings based on daily outstanding balances during 2017 was $53.3 million, with a weighted-average interest rate asduring the period of December 31 are shown in the following table:1.38%.

  2014 2013
    Interest   Interest
  Balance Rate Balance Rate
  (Millions of Dollars, except for percentages)
         
Commercial paper $306.8 0.25% $174.5 0.22%

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

  2014 2013
  (Millions of Dollars, except for percentages)
     
Maximum Commercial Paper Outstanding $401.0
 $354.5
Average Commercial Paper Outstanding $179.5
 $98.0
Weighted-Average Interest Rate 0.22% 0.22%

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

As of December 31, 2014,2017, we had approximately $494.9$287.9 million of available undrawn linescapacity under our bank back-up credit facility and $306.8$210.9 million of commercial paper outstanding that was supported by the available lines of credit. credit facility.

In December 2014, we amendedApril 2017, our credit facility to extend its expiration from December 2017 to December 2019. As of December 31, 2014, ourconsolidated subsidiary, hadBostco, paid off a $22.4 million note payable to Wisconsinour parent, WEC Energy with a weighted-average interest rate of 6.75%.Group.


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 2017
Revolving credit facility October 2022 $500.0
     
Less:    
Letters of credit issued inside credit facility   $1.2
Commercial paper outstanding   210.9
     
Available capacity under existing agreement   $287.9
83Wisconsin Electric Power Company

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K
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 (ERISA) defaults and change of control.

As of December 31, 2014, we were in compliance with all financial covenants.
NOTE 11—LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS


L -- DERIVATIVE INSTRUMENTSSee our statements of capitalization for details on our long-term debt.

We utilize derivatives as partDebentures and Notes

The following table shows the future maturities of our risk management program to manage the volatility and costs of purchased power, generation and natural gas purchases for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the PSCW.

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of December 31, 2014, we recognized $8.4 million in regulatory assets and $12.2 million in regulatory liabilities related to derivatives in comparison to $0.3 million in regulatory assets and $8.1 million in regulatory liabilitieslong-term debt outstanding (excluding obligations under capital leases) as of December 31, 2013.

We record our current derivative assets on the balance sheet in other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $0.6 million is recorded in other deferred charges and other assets as of December 31, 2014, and the long-term portion of derivative liabilities of $0.7 million is recorded in other deferred credit and other liabilities as of December 31, 2014. Our Consolidated Balance Sheets as of December 31, 2014 and 2013 include:

2017:
  December 31, 2014 December 31, 2013
  
Derivative
Asset
 
Derivative
Liability
 
Derivative
Asset
 
Derivative
Liability
  (Millions of Dollars)
Natural Gas $2.3
 $7.1
 $2.8
 $0.1
Fuel Oil —
 —
 0.6
 —
FTRs 7.0
 —
 3.5
 —
Coal 3.3
 0.2
 2.1
 0.2
Total $12.6
 $7.3
 $9.0
 $0.3
(in millions)  
2018 $250.0
2019 250.0
2020 —
2021 300.0
2022 —
Thereafter 1,885.0
Total $2,685.0

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

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

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


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

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

The fair value amounts recognizedWe 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 rightbonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to reclaim cash collateral or the obligation to return cash collateraldate of purchase. As of December 31, 2017, the repurchased bonds were still outstanding, but are not offset againstreported 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 fair value amounts recognized for derivative instruments executedmethod 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 same counterpartyleased plants and corresponding obligations under the same master netting arrangement. The table below shows derivative assetscapital 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 derivative liabilities if derivative instruments by counterparty were presented netmaintenance in our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on theour balance sheet as of December 31, 2014sheets. See Note 5, Regulatory Assets and 2013.Liabilities, for more information on our plant related capital leases.

 December 31, 2014 December 31, 2013
 Derivative Derivative Derivative Derivative
 Asset Liability Asset Liability
 (Millions of Dollars)
        
Gross Amount Recognized on the Balance Sheet$12.6
 $7.3
 $9.0
 $0.3
Gross Amount Not Offset on Balance Sheet (a)(0.4) (6.8) —
 —
Net Amount$12.2
 $0.5
 $9.0
 $0.3
        

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


M -- FAIR VALUE MEASUREMENTSPower Purchase Commitment

Fair value measurements require enhanced disclosures about assetsIn 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 liabilities that are measured and reportedwith 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 establishrecorded 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 hierarchal disclosure framework which prioritizes and ranksstraight-line basis over the leveloriginal 25-year term of observable inputs used in measuring fair value.the contract.

Fair value isWe treat the price that wouldlong-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 received uponreduced to zero over the saleremaining life of an asset or paidthe contract. The total obligation under the capital lease was $27.0 million as of December 31, 2017, and will decrease to transfer a liabilityzero 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 an orderly transaction between market participantsservice 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 measurement date (exit price). We primarily apply the market approach for recurringestimated 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.$727.4 million. We are ableamortizing the leased units on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to classify fair value balances based onbe recovered through our rates, as supported by the observability of those inputs. The hierarchy gives2001 leased generation law. Due to the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1)timing and the lowest priorityamounts of the minimum lease payments, we expect the regulatory asset to unobservable inputs (Level 3).increase to approximately $129.1 million in the year 2021 for PWGS 1 and to approximately $124.4 million in the year 2023 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 $644.7 million as of December 31, 2017, and will decrease to zero over the remaining lives of the contracts.

AssetsElm Road Generating Station

We are leasing ER 1, ER 2, and liabilities measured and reported at fair valuethe common facilities, which are classified and disclosed in onealso 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 following categories: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

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

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been recorded at the estimated fair value of $2,141.4 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 $517.9 million in the year 2028 for ER 1 and to approximately $425.0 million in the year 2029 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 $2,194.6 million as of December 31, 2017, and will decrease to zero over the remaining lives of the contracts.

We paid the following lease payments during 2017, 2016, and 2015:
(in millions) 2017 2016 2015
Long-term power purchase commitment $7.2
 $37.6
 $36.2
PWGS  85.0
 82.4
 103.8
ERGS 335.5
 329.8
 306.7
Total $427.7
 $449.8
 $446.7

As a result of the Tax Legislation, future PWGS and ERGS lease payments were recalculated and are expected to decrease by approximately $50.0 million annually beginning in 2018. The reduction in lease payments is not expected to impact earnings as it will be recorded as a reduction to regulatory assets until our next rate case. See Note 5, Regulatory Assets and Liabilities, and Note 12, Income Taxes, for more information on the Tax Legislation.

The following table summarizes our capitalized leased facilities as of December 31:
(in millions) 2017 2016
Long-term power purchase commitment    
Under capital lease $140.3
 $140.3
Accumulated amortization (115.2) (109.5)
Total long-term power purchase commitment $25.1
 $30.8
     
PWGS     
Under capital lease $727.4
 $704.2
Accumulated amortization (305.1) (274.7)
Total PWGS  $422.3
 $429.5
     
ERGS    
Under capital lease $2,141.4
 $2,053.5
Accumulated amortization (525.6) (453.6)
Total ERGS $1,615.8
 $1,599.9
     
Total leased facilities $2,063.2
 $2,060.2


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)20142017 Form 10-K72Wisconsin Electric Power Company
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significantFuture minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2017 are as follows:
(in millions) Power Purchase Commitment PWGS ERGS Total
2018 $14.7
 $96.3
 $287.7
 $398.7
2019 15.5
 96.3
 287.7
 399.5
2020 16.4
 96.3
 287.7
 400.4
2021 17.2
 96.3
 287.7
 401.2
2022 7.6
 96.3
 287.6
 391.5
Thereafter —
 857.3
 5,029.5
 5,886.8
Total minimum lease payments 71.4
 1,338.8
 6,467.9
 7,878.1
Less: Estimated executory costs (33.1) —
 —
 (33.1)
Net minimum lease payments 38.3
 1,338.8
 6,467.9
 7,845.0
Less: Interest (11.3) (694.1) (4,273.3) (4,978.7)
Present value of minimum lease payments 27.0
 644.7
 2,194.6
 2,866.3
Less: Due currently (3.7) (19.4) (19.4) (42.5)
Long-term obligations under capital lease $23.3
 $625.3
 $2,175.2
 $2,823.8

NOTE 12—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) 2017 2016 2015
Current tax expense $81.5
 $4.8
 $33.1
Deferred income taxes, net 110.6
 207.3
 180.0
Investment tax credit, net (0.9) (1.1) (1.1)
Total income tax expense $191.2
 $211.0
 $212.0

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:
  2017 2016 2015
(in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate
Expected tax at statutory federal tax rates $184.4
 35.0 % $201.4
 35.0 % $205.7
 35.0 %
State income taxes net of federal tax benefit 27.9
 5.3 % 31.8
 5.5 % 31.0
 5.3 %
Production tax credits (17.6) (3.3)% (16.5) (2.8)% (17.8) (3.0)%
Domestic production activities deduction (7.8) (1.5)% (7.8) (1.4)% (7.8) (1.3)%
AFUDC – Equity (1.1) (0.2)% (1.5) (0.3)% (2.0) (0.3)%
Investment tax credit restored (0.9) (0.2)% (1.1) (0.2)% (1.1) (0.2)%
Other, net 6.3
 1.1 % 4.7
 0.8 % 4.0
 0.5 %
Total income tax expense $191.2
 36.2 % $211.0
 36.6 % $212.0
 36.0 %

Deferred Income Tax Assets and Liabilities

On December 22, 2017, the Tax Legislation was signed into law. For businesses, the Tax Legislation reduces the corporate federal tax rate from a maximum of 35% to a 21% rate effective January 1, 2018. We estimated a preliminary tax benefit related to the fair value measurement.re-measurement of our deferred taxes in the amount of approximately $1,065 million. Accordingly, this amount has been recorded as both an increase to regulatory liabilities as well as a decrease to certain existing regulatory assets as of December 31, 2017. Our assessmentrevaluation of our deferred tax assets and liabilities is subject to further clarification of the significancenew law that cannot be estimated at this

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time. The impact of the Tax Legislation could materially differ from this estimate due to, among other things, changes in interpretations and assumptions we have made.

On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provides for a particular inputmeasurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the fair value measurementcomplex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in its entirety requires judgmentthe financial statements as a result of the Tax Legislation are to be considered "provisional" as discussed in SAB 118 and considers factors specificsubject to revision. We are awaiting additional guidance from industry and income tax authorities in order to finalize our accounting.

The components of deferred income taxes as of December 31 were as follows:
(in millions) 2017 2016
Deferred tax assets    
Tax gross up – regulatory items $240.1
 $—
Future tax benefits 133.1
 143.7
Deferred revenues 128.8
 207.2
Employee benefits and compensation 50.2
 77.6
Construction advances 15.0
 20.0
Uncollectible account expense 12.5
 16.1
Emission allowances 0.1
 0.2
Other 54.8
 70.9
Total deferred tax assets 634.6
 535.7
     
Deferred tax liabilities    
Property-related 1,487.0
 2,257.3
Employee benefits and compensation 117.4
 179.3
Deferred transmission costs 60.1
 93.1
Prepaid tax, insurance, and other 33.8
 50.2
Investment in transmission affiliate —
 195.1
Other 91.8
 94.0
Total deferred tax liabilities 1,790.1
 2,869.0
Deferred tax liability, net $1,155.5
 $2,333.3

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

As of December 31, 2017, we had $4.0 million and $125.6 million of federal charitable contribution and tax credit carryforwards resulting in deferred tax assets of $0.8 million and $125.6 million, respectively. These federal charitable contribution carryforwards begin to expire in 2020 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, 2016, we had approximately $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. As of December 31, 2017 we had $74.7 million and $31.9 million of state net operating loss and state charitable contribution carryforwards resulting in deferred tax assets of $4.7 million and $2.0 million, respectively. These state net operating loss carryforwards begin to expire in 2035 and state charitable contribution carryforwards begin to expire in 2017. We expect to have future taxable income sufficient to utilize these deferred tax assets. As of December 31, 2016 we had $149.9 million state net operating loss carryforwards resulting in deferred tax assets of $7.5 million.

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) 2017 2016
Balance as of January 1 $5.1
 $6.1
Reductions for tax positions of prior years (5.1) (1.0)
Balance as of December 31 $—
 $5.1

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The amount of unrecognized tax benefits as of December 31, 2017 and 2016 excludes deferred tax assets related to uncertainty in income taxes of zero and $5.1 million, respectively. As of December 31, 2017 and 2016, 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, 2017, 2016, and 2015, we recognized $0.7 million of interest income, $0.2 million of interest expense, and $0.1 million of interest income, respectively, in our income statements. For the years ended December 31, 2017, 2016, and 2015, we recognized no penalties in our income statements. As of December 31, 2017, we had no interest accrued and no penalties accrued on our balance sheets. As of December 31, 2016, we had $0.7 million of accrued interest and no penalties accrued on our balance sheets.

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

Our primary tax jurisdictions include Federal and the state of Wisconsin. With a few exceptions, we are no longer subject to federal income tax examination by the IRS for years prior to 2014. As of December 31, 2017, we were subject to examination by the Wisconsin taxing authority for tax years 2013 through 2017.

NOTE 13—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:

Recurring Fair Value Measures As of December 31, 2014
  Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
Assets:        
Derivatives $0.4
 $5.2
 $7.0
 $12.6
Total $0.4
 $5.2
 $7.0
 $12.6
Liabilities:        
Derivatives $6.8
 $0.5
 $—
 $7.3
Total $6.8
 $0.5
 $—
 $7.3
  December 31, 2017
(in millions) Level 1 Level 2 Level 3 Total
Derivative assets        
Natural gas contracts $0.5
 $0.1
 $—
 $0.6
   Petroleum products contracts 0.9
 —
 —
 0.9
FTRs —
 —
 2.4
 2.4
Coal contracts —
 0.7
 —
 0.7
Total derivative assets $1.4
 $0.8
 $2.4
 $4.6
         
Derivative liabilities        
Natural gas contracts $2.0
 $0.1
 $—
 $2.1
Coal contracts —
 0.3
 —
 0.3
Total derivative liabilities $2.0
 $0.4
 $—
 $2.4

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
  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

Derivatives reflect positions we holdThe derivative assets and liabilities listed in exchange-traded derivativethe tables above include options, futures, physical commodity contracts, and OTC derivative contracts. Exchange-traded derivative contracts,other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which include futures and exchange-traded options, are generally based on unadjusted quoted pricesused to manage electric transmission congestion costs 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 pricesMISO Energy Markets. See Note 14, Derivative Instruments, 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.more information.


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


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

  2014 2013
  (Millions of Dollars)
     
Balance as of January 1 $3.5
 $4.7
Realized and unrealized gains (losses) —
 —
Purchases 15.6
 10.6
Issuances —
 —
Settlements (12.1) (11.8)
Transfers in and/or out of Level 3 —
 —
Balance as of December 31 $7.0
 $3.5
(in millions) 2017 2016 2015
Balance at the beginning of the period $3.1
 $1.6
 $7.0
Purchases 6.9
 8.1
 3.9
Settlements (7.6) (6.6) (9.3)
Balance at the end of the period $2.4
 $3.1
 $1.6

Derivative instruments reflected in Level 3Fair Value 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 -- DerivativeFinancial Instruments for further information on the offset to regulatory assets and liabilities.

The carrying amount and estimated fair value of certain of our recordedfollowing table shows the financial instruments as of December 31included on our balance sheets that are as follows:

not recorded at fair value:
  2014 2013
  Carrying Fair Carrying Fair
Financial Instruments Amount Value Amount Value
  (Millions of Dollars)
         
Preferred stock, no redemption required $30.4
 $27.1
 $30.4
 $26.0
Long-term debt including current portion $2,437.0
 $2,759.6
 $2,487.0
 $2,634.7
  December 31, 2017 December 31, 2016
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock $30.4
 $30.5
 $30.4
 $28.8
Long-term debt, including current portion 2,662.3
 2,976.3
 2,661.1
 2,923.4

NOTE 14—DERIVATIVE INSTRUMENTS

The carrying valuefollowing table shows our derivative assets and derivative liabilities:
  December 31, 2017 December 31, 2016
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current        
   Natural gas contracts $0.6
 $1.9
 $6.3
 $0.1
   Petroleum products contracts 0.9
 —
 0.2
 0.1
   FTRs 2.4
 —
 3.1
 —
   Coal contracts 0.6
 0.1
 1.5
 0.5
   Total other current $4.5
 $2.0
 $11.1
 $0.7
         
Other long-term        
   Natural gas contracts $—
 $0.2
 $0.5
 $—
   Coal contracts 0.1
 0.2
 0.4
 —
   Total other long-term $0.1
 $0.4
 $0.9
 $—
Total $4.6
 $2.4
 $12.0
 $0.7

Our estimated notional sales volumes and realized gains (losses) were as follows:
  December 31, 2017 December 31, 2016 December 31, 2015
(in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains (Losses)
Natural gas contracts 26.9 Dth $(1.0) 35.3 Dth $(12.3) 24.0 Dth $(12.6)
Petroleum products contracts 16.7 gallons (1.4) 10.3 gallons (2.6) 4.0 gallons (0.2)
FTRs 27.1 MWh 7.6
 25.3 MWh 7.3
 22.8 MWh 3.2
Total   $5.2
   $(7.6)   $(9.6)

At December 31, 2017, we had posted cash collateral of net$4.9 million in our margin accounts, receivable, accounts payable and short-term borrowings approximates fair value due to the short-term natureat December 31, 2016, we had received cash collateral of these instruments. The fair value of$3.4 million in 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.margin accounts.


2017 Form 10-K76Wisconsin Electric Power Company
Table of Contents

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
  December 31, 2017 December 31, 2016
(in millions) 
Derivative
Assets
 Derivative Liabilities 
Derivative
Assets
 Derivative Liabilities
Gross amount recognized on the balance sheet $4.6
 $2.4
 $12.0
 $0.7
Gross amount not offset on the balance sheet (1.3) (2.0)
(1) 
(3.6)
(2) 
(0.2)
Net amount $3.3
 $0.4
 $8.4
 $0.5

(1)
Includes cash collateral posted of $0.7 million at December 31, 2017.

(2)
Includes cash collateral received of $3.4 million at December 31, 2016.

N --NOTE 15—EMPLOYEE BENEFITS

PensionsPension and Other Post-retirement Benefits:Postretirement Employee Benefits

We participate in Wisconsin Energy'sWEC 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 the Companyus after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Approximately half of our projected benefit obligation relates to benefits based upon years of service and final average salary. New management employees hired after December 31, 2014 will receive a 6% annual Companycompany contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.

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


87Wisconsin Electric Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

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

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


2017 Form 10-K77Wisconsin Electric Power Company
Table of Contents

The following table presents details abouttables provide a reconciliation of the pensionchanges in our plans' benefit obligations and OPEB plans:

fair value of assets:
  Pension OPEB
  2014 2013 2014 2013
  (Millions of Dollars)
Change in Benefit Obligation        
Benefit Obligation at January 1 $1,223.1
 $1,310.3
 $292.4
 $305.4
Service cost 9.4
 13.9
 8.1
 9.5
Interest cost 59.3
 52.4
 14.4
 12.7
Participants' contributions —
 —
 8.4
 8.1
Plan amendments —
 (0.9) (5.2) —
Actuarial loss (gain) 110.8
 (73.9) 24.3
 (22.7)
Other accrued benefits (0.1) —
 —
 —
Gross benefits paid (87.3) (78.7) (21.1) (21.3)
Federal subsidy on benefits paid N/A
 N/A
 1.0
 0.7
Benefit Obligation at December 31 $1,315.2
 $1,223.1
 $322.3
 $292.4
         
Change in Plan Assets        
Fair Value at January 1 $1,168.9
 $1,121.1
 $222.4
 $194.8
Actual earnings on plan assets 71.2
 119.0
 12.0
 30.7
Employer contributions 7.2
 7.5
 3.2
 10.1
Participants' contributions —
 —
 8.4
 8.1
Gross benefits paid (87.3) (78.7) (21.1) (21.3)
Fair Value at December 31 $1,160.0
 $1,168.9
 $224.9
 $222.4
         
Net liability $155.2
 $54.2
 $97.4
 $70.0
  Pension Costs OPEB Costs 
(in millions) 2017 2016 2017 2016 
Change in benefit obligation         
Obligation at January 1 $1,177.0
 $1,290.6
 $298.5
 $313.8
 
Service cost 12.2
 10.5
 7.0
 7.3
 
Interest cost 47.0
 49.7
 12.1
 13.2
 
Participant contributions —
 —
 5.7
 8.8
 
Plan amendments —
 (2.6) (6.8) —
 
Net transfer to/from affiliates (13.4)
(1) 
(121.1)
(2) 
(3.3)
(1) 
(17.0)
(2) 
Actuarial loss (gain) 53.1
 25.3
 5.1
 (9.7) 
Benefit payments (82.0) (75.4) (16.5) (19.0) 
Federal subsidy on benefits paid N/A
 N/A
 1.7
 1.1
 
Obligation at December 31 $1,193.9
 $1,177.0
 $303.5
 $298.5
 
          
Change in fair value of plan assets         
Fair value at January 1 $1,102.8
 $1,179.3
 $205.1
 $216.1
 
Actual return on plan assets 121.9
 73.0
 25.9
 13.5
 
Employer contributions 5.1
 5.3
 3.2
 2.7
 
Participant contributions —
 —
 5.7
 8.8
 
Net transfer to/from affiliates (13.7)
(1) 
(79.4)
(2) 
(3.3)
(1) 
(17.0)
(2) 
Benefit payments (82.0) (75.4) (16.5) (19.0) 
Fair value at December 31 $1,134.1
 $1,102.8
 $220.1
 $205.1
 
Funded status at December 31 $(59.8) $(74.2) $(83.4) $(93.4) 

(1)
Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities, primarily a result of our customer service employees being transferred to WBS.
Amounts
(2)
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 inon our Consolidated Balance Sheets as ofbalance sheets at December 31 related to the funded status of the benefit plans consisted of:

were as follows:
  Pension OPEB
  2014 2013 2014 2013
  (Millions of Dollars)
         
Other long-term assets $—
 $34.3
 $1.9
 $1.6
Other long-term liabilities $155.2
 $88.5
 $99.3
 $71.6
Net liability $155.2
 $54.2
 $97.4
 $70.0
  Pension Costs OPEB Costs
(in millions) 2017 2016 2017 2016
Pension and OPEB obligations $(59.8) $(74.2) $(83.4) $(93.4)

The accumulated benefit obligation for all defined benefit pension plans was $1,314.3$1,192.4 million and $1,222.3$1,175.8 million as of December 31, 20142017 and 2013,2016, 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) 2017 2016
Projected benefit obligation $1,193.9
 $1,177.0
Accumulated benefit obligation 1,192.4
 1,175.8
Fair value of plan assets 1,134.1
 1,102.8
88Wisconsin Electric Power Company

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

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31 and are recorded as a regulatory asset on our balance sheet:31:
  Pension Costs OPEB Costs
(in millions) 2017 2016 2017 2016
Net regulatory assets        
Net actuarial loss (gain) $485.4
 $518.5
 $(1.6) $4.6
Prior service costs (credits) (1.0) 0.2
 (8.4) (3.0)
Total $484.4
 $518.7
 $(10.0) $1.6


  Pension OPEB
  2014 2013 2014 2013
  (Millions of Dollars)
         
Net actuarial loss (gain) $476.4
 $384.7
 $20.7
 $(7.6)
Prior service costs (credits) 6.3
 8.3
 (5.2) (1.7)
Total - Regulatory Assets (Liabilities) $482.7
 $393.0
 $15.5
 $(9.3)
2017 Form 10-K78Wisconsin Electric Power Company
Table of Contents

We estimateThe following table shows the estimated amounts that 2015will be amortized into net periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs (credits) referred to above of $38.0 million and $(0.2) million, respectively.cost during 2018:
(in millions) Pension Costs OPEB Costs
Net actuarial loss $37.5
 $—
Prior service costs (credits) 0.9
 (2.3)
Total 2018 – estimated amortization
 $38.4
 $(2.3)

The components of net periodic pension and OPEB costsbenefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 arewere as follows:
  Pension Costs OPEB Costs
(in millions) 2017 2016 2015 2017 2016 2015
Service cost $12.2
 $10.5
 $14.7
 $7.0
 $7.3
 $9.0
Interest cost 47.0
 49.7
 52.9
 12.1
 13.2
 13.4
Expected return on plan assets (76.6) (77.7) (83.6) (14.7) (14.0) (16.0)
Plan settlement 4.1
 —
 —
 —
 —
 —
Amortization of prior service cost (credit) 1.1
 1.6
 2.0
 (1.4) (1.1) (1.1)
Amortization of net actuarial loss 35.4
 32.4
 35.6
 —
 1.0
 1.0
Net periodic benefit cost $23.2
 $16.5
 $21.6
 $3.0
 $6.4
 $6.3

The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:
  Pension OPEB
  2017 2016 2017 2016
Discount rate 3.65% 4.15% 3.65% 4.20%
Rate of compensation increase 3.20% 3.20% N/A N/A
Assumed medical cost trend rate (pre 65) N/A N/A 6.50% 7.00%
Ultimate trend rate N/A N/A 5.00% 5.00%
Year ultimate trend rate is reached N/A N/A 2024 2021
Assumed medical cost trend rate (post 65) N/A N/A 6.18% 7.00%
Ultimate trend rate N/A N/A 5.00% 5.00%
Year ultimate trend rate is reached N/A N/A 2028 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
  2017 2016 2015
Discount rate 4.12% 4.45% 4.15%
Expected return on plan assets 7.00% 7.00% 7.00%
Rate of compensation increase 3.20% 3.50% 4.00%

  Pension OPEB
  2014 2013 2012 2014 2013 2012
  (Millions of Dollars)
Net Periodic Benefit Cost            
Service cost $9.4
 $13.9
 $19.8
 $8.1
 $9.5
 $9.8
Interest cost 59.3
 52.4
 56.8
 14.4
 12.7
 16.7
Expected return on plan assets (79.1) (77.2) (71.8) (16.2) (14.5) (13.0)
Amortization of:            
Transition obligation —
 —
 —
 —
 —
 0.3
Prior service cost (credit) 2.0
 2.2
 2.1
 (1.7) (1.9) (1.9)
Actuarial loss 26.9
 41.7
 30.6
 0.2
 1.5
 5.0
Settlement charge —
 1.5
 —
 —
 —
 —
Other —
 —
 0.4
 —
 —
 —
Net Periodic Benefit Cost $18.5
 $34.5
 $37.9
 $4.8
 $7.3
 $16.9
  OPEB Costs
  2017 2016 2015
Discount rate 4.10% 4.45% 4.20%
Expected return on plan assets 7.25% 7.25% 7.25%
Assumed medical cost trend rate (Pre 65/Post 65) 7.00% 7.50% 7.50%
Ultimate trend rate 5.00% 5.00% 5.00%
Year ultimate trend rate is reached 2021 2021 2021

  Pension OPEB
  2014 2013 2012 2014 2013 2012
Weighted-Average assumptions used to            
determine benefit obligations as of Dec. 31            
Discount rate 4.15% 5.00% 4.10% 4.20% 4.95% 4.15%
Rate of compensation increase 4.00% 4.00% 4.00% N/A N/A N/A
             
Weighted-Average assumptions used to            
determine net cost for year ended Dec. 31            
Discount rate 5.00% 4.10% 5.05% 4.95% 4.15% 5.20%
Expected return on plan assets 7.25% 7.25% 7.25% 7.50% 7.50% 7.50%
Rate of compensation increase 4.00% 4.00% 4.00% N/A N/A N/A
             
Assumed health care cost trend rates as of Dec. 31          
Health care cost trend rate assumed for next year (Pre 65 / Post 65)   7.5%/7.5% 7.5%/7.5% 7.5%/7.5%
Rate that the cost trend rate gradually adjusts to   5.00% 5.00% 5.00%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65) 2021/2021 2021/2021 2017/2017

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2014, 2013 and 2012. WisconsinWEC 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 2018, the expected return on assets assumption is 7.00% for the pension plan and 7.25% for the OPEB plan.


2017 Form 10-K8979Wisconsin Electric Power Company
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K


AAssumed 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, 2017, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:

  1% Increase 1% Decrease
  (Millions of Dollars)
Effect on    
Post-retirement benefit obligation $29.3
 $(24.4)
Total of service and interest cost components $3.1
 $(2.5)
(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 29.3
 (24.2)

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

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

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

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

Pension and OPEB plan investments are recorded at fair value. See Note 1(m), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.

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

class:
  As of December 31, 2014
Asset Category - Pension Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $5.1
 $—
 $—
 $5.1
Equities:        
U.S. Equity 404.5
 —
 —
 404.5
International Equity 103.3
 23.9
 —
 127.2
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 34.2
 481.2
 —
 515.4
International Bonds 63.7
 34.8
 —
 98.5
Private equity and real estate —
 —
 9.3
 9.3
Total $610.8
 $539.9
 $9.3
 $1,160.0
  December 31, 2017
  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 $—
 $6.6
 $—
 $6.6
 $2.1
 $0.5
 $—
 $2.6
Equity securities:                
Unites States Equity 109.4
 0.1
 —
 109.5
 29.0
 —
 —
 29.0
International Equity 114.4
 —
 —
 114.4
 32.2
 —
 —
 32.2
Fixed income securities: *                
United States Bonds 75.9
 467.8
 —
 543.7
 24.4
 46.3
 —
 70.7
International Bonds 9.7
 32.8
 —
 42.5
 1.7
 2.9
 —
 4.6
Private Equity and Real Estate —
 20.6
 55.3
 75.9
 —
 1.4
 3.8
 5.2
  $309.4
 $527.9
 $55.3
 $892.6
 $89.4
 $51.1
 $3.8
 $144.3
Investments measured at net asset value       $241.5
       $75.8
Total $309.4
 $527.9
 $55.3
 $1,134.1
 $89.4
 $51.1
 $3.8
 $220.1

*This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

2017 Form 10-K9080Wisconsin Electric Power Company
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K


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

(a)*This category represents investment grade bonds of U.S.United States and foreign issuers denominated in U.S. dollars from diverse industries.
The following table summarizes the fair value of our share of OPEB plan assets by asset category within the fair value hierarchy:

  As of December 31, 2014
Asset Category - OPEB Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $0.9
 $—
 $—
 $0.9
Equities:        
U.S. Equity 98.4
 —
 —
 98.4
International Equity 28.5
 1.7
 —
 30.2
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 2.4
 75.8
 —
 78.2
International Bonds 11.8
 4.7
 —
 16.5
Private equity and real estate —
 —
 0.7
 0.7
Total $142.0
 $82.2
 $0.7
 $224.9

  As of December 31, 2013
Asset Category - OPEB Level 1 Level 2 Level 3 Total
  (Millions of Dollars)
         
Cash and Cash Equivalents $1.8
 $—
 $—
 $1.8
Equities:        
U.S. Equity 100.5
 —
 —
 100.5
International Equity 31.8
 1.9
 —
 33.7
Fixed Income:        
   Short, Intermediate and Long-term Bonds (a)        
U.S. Bonds 5.7
 65.4
 —
 71.1
International Bonds 11.4
 3.9
 —
 15.3
Total $151.2
 $71.2
 $—
 $222.4

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

In December 2014, ourThe following tables set forth a reconciliation of changes in the fair value of pension and OPEB plans began investing in private equity funds which are aplan assets categorized as Level 3 investment.in the fair value hierarchy:
  Private Equity and Real Estate
(in millions) Pension OPEB
Beginning balance at January 1, 2017 $11.0
 $0.7
Realized and unrealized gains 1.9
 0.2
Purchases 22.3
 1.5
Transfers into level 3 20.1
 1.4
Ending balance at December 31, 2017 $55.3
 $3.8

  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

Cash Flows

We expect to contribute $3.9 million to the pension plans and $0.1 million to the OPEB plans in 2018, dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

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
2018 $92.4
 $13.5
2019 90.1
 14.2
2020 89.2
 14.9
2021 86.0
 15.7
2022 82.3
 16.2
2023-2027 368.2
 85.5


2017 Form 10-K9181Wisconsin Electric Power Company
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

Cash Flows:

Historical employer contributions:
  Pension  
Year Qualified Non-Qualified OPEB
  (Millions of Dollars)
       
2012 $88.5
 $6.0
 $13.6
2013 $—
 $7.5
 $10.1
2014 $—
 $7.2
 $3.2
Savings Plans

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

Estimated benefit payments:
     
     
Year Pension Gross OPEB
  (Millions of Dollars)
     
2015 $91.8
 $13.9
2016 $91.5
 $14.8
2017 $92.1
 $16.0
2018 $89.5
 $17.1
2019 $89.4
 $18.2
2020-2024 $429.5
 $99.3

Savings Plans:We sponsor 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. UnderA 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 all of these plans we expensed matching contributions of $13.0were $11.7 million, $13.0 in 2017, $10.4 million in 2016, and $12.5$13.0 million during 2014, 2013 and 2012, respectively. in 2015.

Postemployment Benefits:Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $1.8 million and $2.8 million as of December 31, 2014 and 2013, respectively.
NOTE 16—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 for cost of service and certain state regulatory commissions for routing and siting of transmission projects. Effective 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 the recognition of a gain or loss. The following table provides a reconciliation of our investment in ATC during the years ended December 31:
(in millions) 2017 2016 2015
Balance at January 1 $402.0
 $382.2
 $372.9
Less: Transfer of ownership interest 402.0
 —
 —
Add: Earnings from equity method investment —
 55.5
 47.8
Add: Capital contributions —
 16.1
 4.6
Less: Distributions —
 51.7
*42.9
Less: Other —
 0.1
 0.2
Balance at December 31 $—
 $402.0
 $382.2

*Of this amount, $13.4 million was recorded as a receivable from ATC at December 31, 2016.

See Note 4, Related Parties, for more information on transactions with ATC.

O -- NOTE 17—SEGMENT REPORTINGINFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2017, we reported two segments, which are a subsidiary of Wisconsin Energydescribed below.

Our utility segment includes our electric 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.
operations. Our electric utility engagesoperations are engaged in the generation, distribution, and sale of electric energyelectricity in southeastern Wisconsin (including metropolitan Milwaukee), east central andWisconsin, 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.Michigan to UMERC, with the exception of Tilden. See Note 4, Related Parties, and Note 21, 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 isoperations 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 inwithin southeastern, east central, and northern Wisconsin. Our steam utility produces, distributes and sells steam to space heating and processing customers in the Milwaukee, Wisconsin area.

Total asset information is not provided for reportable segments because as an integrated electric, natural gasOur other segment includes Bostco, our non-utility subsidiary that was originally formed to develop and steam utility, significant assets are not dedicated to a specific reportable segment. Reporting assets by segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operationinvest in real estate. In March 2017, we sold substantially all of the reportable segments onremaining assets of Bostco. See Note 3, Dispositions, for more information. Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a stand-alone basis.for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information.


2017 Form 10-K9282Wisconsin Electric Power Company
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K


SummarizedAll of our operations and assets are located within the United States. The following tables show summarized financial information concerningrelated to our reportable segments for each of the three years ended December 31, 2014 is shown in the following table:2017, 2016, and 2015.
2017 (in millions)
 Utility Other Wisconsin Electric Power Company Consolidated
Operating revenues $3,711.7
 $—
 $3,711.7
Other operation and maintenance 1,358.5
 —
 1,358.5
Depreciation and amortization 331.6
 —
 331.6
Operating income 625.6
 —
 625.6
Interest expense 117.0
 0.3
 117.3
Capital expenditures 596.1
 —
 596.1
Total assets 13,121.6
 —
 13,121.6

  Reportable Segments    
Year Ended Electric Gas Steam Other (a) Total
  (Millions of Dollars)
December 31, 2014          
Operating Revenues (b) $3,401.1
 $614.2
 $44.1
 $—
 $4,059.4
Depreciation and Amortization $261.5
 $30.5
 $3.7
 $—
 $295.7
Operating Income (c) $565.6
 $77.2
 $7.6
 $—
 $650.4
Equity in Earnings          
of Transmission Affiliate $57.9
 $—
 $—
 $—
 $57.9
Capital Expenditures $470.2
 $67.9
 $2.8
 $—
 $540.9
           
December 31, 2013          
Operating Revenues (b) $3,308.7
 $451.9
 $39.6
 $—
 $3,800.2
Depreciation and Amortization $249.5
 $25.5
 $3.6
 $—
 $278.6
Operating Income (Loss) (c) $533.2
 $69.8
 $2.9
 $—
 $605.9
Equity in Earnings          
of Transmission Affiliate $60.2
 $—
 $—
 $—
 $60.2
Capital Expenditures $438.5
 $57.8
 $10.6
 $—
 $506.9
           
December 31, 2012          
Operating Revenues (b) $3,193.9
 $385.1
 $34.3
 $—
 $3,613.3
Depreciation and Amortization $230.3
 $23.9
 $3.4
 $—
 $257.6
Operating Income (c) $536.5
 $50.0
 $(3.2) $—
 $583.3
Equity in Earnings          
of Transmission Affiliate $57.6
 $—
 $—
 $—
 $57.6
Capital Expenditures $524.9
 $50.8
 $—
 $0.1
 $575.8
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

(a)Other includes primarily non-utility property and investments, materials and supplies, deferred charges and other corporate items.
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

(b)We account for intersegment revenues at a tariff rate established by the PSCW. Intersegment revenues were not material.
NOTE 18—VARIABLE INTEREST ENTITIES

(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.
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, electric transmission 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. 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 16, Investment in American Transmission Company, for more information.


P -- RELATED PARTIES

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

American Transmission Company LLC:   As of December 31, 2014, we have a 23.0% interest in ATC. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which is reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while projects are under construction. ATC reimburses us for these costs when new generation is placed in service.


2017 Form 10-K9383Wisconsin Electric Power Company
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

Purchased Power Agreement

DuringWe have 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 four 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 $71.4 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the years ended December 31, 2014, 20132017, 2016, and 2012, our equity in earnings2015 were $18.0 million, $54.2 million, and distributions received from ATC were as follows:$53.6 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

Equity Investee 2014 2013 2012
  (Millions of Dollars)
Equity in Earnings $57.9
 $60.2
 $57.6
       
Distributions Received $50.5
 $47.8
 $46.1
NOTE 19—COMMITMENTS AND CONTINGENCIES

Summary financial informationWe 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 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. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.

The following table shows our minimum future commitments related to these purchase obligations as of December 31, from the financial statements of ATC is as follows:

2017.
  2014 2013 2012
  (Millions of Dollars)
       
Operating Revenues $635.0
 $626.3
 $603.3
Operating Income $327.6
 $331.3
 $322.2
Net Income $238.7
 $247.6
 $237.4
       
Current Assets $66.4
 $80.7
 $63.1
Non-Current Assets $3,728.7
 $3,509.5
 $3,274.7
Current Liabilities $313.1
 $381.5
 $251.5
Non-Current Liabilities $1,864.8
 $1,676.2
 $1,645.8
      Payments Due By Period
(in millions) Date Contracts Extend Through Total Amounts Committed 2018 2019 2020 2021 2022 Later Years
Electric utility:                
Nuclear 2033 $9,184.5
 $420.1
 $445.4
 $475.1
 $501.1
 $531.2
 $6,811.6
Coal supply and transportation 2020 215.0
 132.2
 53.9
 28.9
 —
 —
 —
Purchased power 2031 93.1
 29.1
 16.6
 13.7
 10.9
 9.0
 13.8
Natural gas utility supply and transportation 2048 462.3
 65.6
 54.8
 43.6
 30.3
 22.6
 245.4
Total   $9,954.9
 $647.0
 $570.7
 $561.3
 $542.3
 $562.8
 $7,070.8

Operating Leases

We providedlease property, plant, and received services fromequipment 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 associated companies during 2014, 2013 and 2012: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 $4.0 million, $5.0 million, and $6.7 million in 2017, 2016, and 2015, respectively.
Company 2014 2013 2012
  (Millions of Dollars)
Affiliate      
       
Services Provided      
We Power (excluding lease payments) $41.5
 $2.8
 $2.3
Wisconsin Gas $81.7
 $83.4
 $78.7
Wisconsin Energy $11.3
 $5.6
 $5.6
Other $1.5
 $1.6
 $1.2
       
Services Received      
We Power (including lease payments) $389.0
 $381.7
 $375.3
Wisconsin Gas $20.6
 $23.6
 $16.6
Wisconsin Energy $15.2
 $10.2
 $23.9
       
Equity Investee - ATC      
       
Services Provided $8.1
 $9.0
 $8.2
       
Services Received $231.4
 $234.2
 $222.7


2017 Form 10-K9484Wisconsin Electric Power Company
Table of Contents

Future minimum payments under noncancelable operating leases are payable as follows:

Year Ending December 31
 
Payments
(in millions)
2018 $3.5
2019 3.4
2020 1.9
2021 1.4
2022 1.5
Later years 23.0
Total $34.7

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 intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:

the development of additional sources of renewable electric energy supply;
the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;
the addition of emission control equipment to existing facilities to comply with 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, super-critical pulverized coal generation, and/or replacement with renewable 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

8-Hour Ozone National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. In December 2017, the EPA designated all the counties along Wisconsin's Lake Michigan shoreline, except Brown, Kewaunee, Marinette, and Oconto Counties, as either partial or full nonattainment. Waukesha and Washington counties were also included due to the counties being in the Milwaukee combined statistical area. 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. Although we will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final, which is expected from the EPA in April 2018, and until the state prepares a draft attainment plan, we believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the CPP, 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 CPP, numerous states (including Wisconsin and Michigan) and other 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 CPP 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. The D.C. Circuit Court of

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)20142017 Form 10-K85Wisconsin Electric Power Company
Table of Contents

Appeals heard one case in September 2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking.

The CPP 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.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In October 2017, the EPA issued a proposed rulemaking to repeal the CPP. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan to implement the CPP.

AsNotwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CODecember 31, 20142 emissions by approximately 40% below 2005 levels by 2030. We have implemented and continue to evaluate numerous options in order to meet our CO20132 reduction goal, such as increased use 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. As a result of WEC Energy Group's generation reshaping plan, we expect to retire approximately 1,547 MW of coal generation by 2020, including Pleasant Prairie power plant and PIPP. See Note 6, Property, Plant, and Equipment, for more information. In addition, we are evaluating our Consolidated Balance Sheets included receivablegoal, and payable balancespossible subsequent actions, with ATC as follows:respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

We are required to report our CO2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2016, we reported aggregated CO2 equivalent emissions of approximately 23.9 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 23.5 million metric tonnes to the EPA for 2017. The level of CO2 and other GHG emissions varies from year to year and is 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.
Equity Investee 2014 2013
  (Millions of Dollars)
Accounts Receivable    
Services provided $0.6
 $0.6
     
Accounts Payable    
Services received $19.3
 $19.5

We are also required to report CO2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2016, we reported aggregated CO2 equivalent emissions of approximately 3.7 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 3.8 million metric tonnes to the EPA for 2017.

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.


2017 Form 10-K86Wisconsin Electric Power Company
Table of Contents
Q -- COMMITMENTS AND CONTINGENCIES

Operating Leases:   We enter into long-term purchase power contractsFacility owners must select from seven compliance options available 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 deemedthe impingement mortality (IM) reduction standard. The rule requires state permitting agencies to qualify as operating leases. In addition, we have various other operating leases, including leasesmake BTA determinations, subject to EPA oversight, for coal cars.

Future minimum payments forIM reduction over the next fiveseveral years and thereafter foras facility permits are reissued. Based on our operating lease contracts are as follows:

 (Millions of Dollars)
  
2015$5.2
20163.9
20173.2
20183.1
20191.2
Thereafter21.5
Total$38.1

Divested Assets:   We provided customary indemnifications to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corporation, in connection with the sale of our interest in Edgewater Generating Unit 5.

Environmental Matters:   We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following,assessment, we believe that future costs in excess ofexisting technologies at our generating facilities satisfy the amounts accrued and/or disclosedIM BTA requirements.

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on all presently knowna 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. Due to our plans to retire PIPP and quantifiable environmental contingenciesPleasant Prairie power plant, we do not believe that BTA determinations for EM will be necessary for these facilities. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the EM BTA requirements, BTA determinations to address EM reduction requirements will not be materialmade until discharge permits are renewed for these facilities. Until that time, we cannot yet determine what, if any, intake structure or operational modifications will be required to our financial position or results of operations.meet the new EM BTA requirements at these other facilities. During 2018, we will continue to evaluate options to address the EM BTA requirements at these plants.

We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a programsigned certification stating that PIPP will be retired no later than the end of comprehensive environmental remediation planningthe next permit cycle (assumed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for former manufacturedPIPP to the MDEQ during 2018, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance.

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.

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. Various petitions challenging the rule were consolidated and are pending in the United States Fifth Circuit Court of Appeals. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule to postpone the earliest compliance dates for the bottom ash transport water and wet flue gas desulfurization wastewater requirements. This rule applies to wastewater discharges from our power plant sitesprocesses in Wisconsin and coal combustion product disposal sites. We perform ongoing assessmentsMichigan. While the ELG compliance deadlines are postponed, the WDNR and the MDEQ have indicated that they will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023.

After a final rule is back in effect, the WDNR and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of our manufactured gas plant sites and related disposal sites,the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would phase 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 would require additional zero liquid discharge or other advanced treatment capital improvements for the OCPP and ERGS. The rule also would require dry fly ash handling, which is already in place at all of our coal combustion product disposal/landfill sites.power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7 and OC 8. We are workingbeginning preliminary engineering for compliance with the WDNRrule and estimate approximately $50 million will be required to design and install these advanced treatment and bottom ash transport systems. This estimate reflects the planned retirements of certain of our generation plants as a result of WEC Energy Group's generation reshaping plan discussed in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.Climate Change above.

Land Quality

Manufactured Gas Plant Sites:Remediation

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 remediatedplant or are at various stages of investigation, monitoring and remediation.stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon on-going analysis, we estimate thatWe 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.


2017 Form 10-K87Wisconsin Electric Power Company
Table of Contents

The future costs for detailed site investigation, and future remediation, costs may range from $6 million to $12 million over the next ten years. This estimate isand monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. AsHistorically, 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) 2017 2016
Regulatory assets $30.4
 $29.9
Reserves for future remediation 18.5
 19.0
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 portfolio 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 electric 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 2017 through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the requirement to 15.0% for 2021. We were in compliance with these requirements as of December 31, 20142017. The revised legislation continues to allow recovery of costs incurred to meet the standards and 2013, we established reserves of $6.5 millionprovides for ongoing review and $10.8 million, respectively, relatedrevision to future remediation costs.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.

NOTE 20—SUPPLEMENTAL CASH FLOW INFORMATION
(in millions) 2017 2016 2015
Cash (paid) for interest, net of amount capitalized $(115.1) $(116.2) $(116.2)
Cash (paid) received for income taxes, net (71.7) 100.2
 (58.5)
Significant non-cash transactions:      
Accounts payable related to construction costs 13.2
 9.1
 11.7
Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2)
 415.4
 —
 —
Transfer of net assets to UMERC (1)
 61.1
 —
 —
Equity settlement of a short-term note receivable between Bostco and our parent company 4.8
 —
 —

(1)
See Note 4, Related Parties, for more information on these transactions.

(2)
The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016.


2017 Form 10-K9588Wisconsin Electric Power Company
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd)2014 Form 10-K

NOTE 21—REGULATORY ENVIRONMENT

Historically,Tax Cuts and Jobs Act of 2017

As ordered by the PSCW, has allowed Wisconsin utilities, including us,we deferred for return to deferratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the costs spentestimated tax benefit of $1,065 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes. See Note 12, Income Taxes, for more information.

2018 and 2019 Rates

During April 2017, we, along with WG and WPS, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which freezes base rates through 2019 for our electric and natural gas customers. Based on the remediationPSCW order, our authorized ROE remains at 10.2%, and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, wewhich have recorded a regulatory asset for remediation costs.been denied.

Coal Combustion Product Landfill Sites:   We aggressively seek environmentally acceptable, beneficial usesIn addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits.

Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

Natural Gas Storage Facilities in Michigan

In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide a portion of the current storage needs for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required various levels of monitoring or remediation. Where we have become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. During 2014, 2013 and 2012, we incurred $0.1 million,$0.1 million and $0.3 million, respectively, in landfill remediation expenses.natural gas utility operations. As of December 31, 2014, we have no reserves established related to coal combustion product landfill sites.

Valley Power Plant Title V Air Permit:   The WDNR renewed VAPP's Title V operating permit in February 2011. The term of the permit is five years. In March 2011, the Sierra Club petitioned the EPA for additional reductions and monitoring for particulate matter and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of this proceedingagreement, we, along with WG and WPS, filed a request with the permit is remandedPSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreement and interstate natural gas transportation contracts related to the WDNR,storage facilities. We also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the plant will continuestorage facilities. During June 2017, the PSCW granted, subject to operate undervarious conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. In September 2017, we entered into the previous operating permit.long-term service agreement for the natural gas storage, which was then approved by the PSCW in November 2017.


R -- SUPPLEMENTAL CASH FLOW INFORMATIONFormation of Upper Michigan Energy Resources Corporation

During the year ended In December 31, 2014, we paid $117.9 million in interest, net of amounts capitalized, and paid $20.8 million in income taxes, net of refunds. During the year ended December 31, 2013, we paid $120.5 million in interest, net of amounts capitalized, and received $39.2 million in net refunds from income taxes. During the year ended December 31, 2012, we paid $109.0 million in interest, net of amounts capitalized, and received $91.2 million in net refunds from income taxes.

As of December 31, 2014, 2013 and 2012, the amount of accounts payable related to capital expenditures was $1.7 million, $4.6 million and $15.7 million, respectively.


S -- SUBSEQUENT EVENT

On January 12, 2015, we, along with Wisconsin Energy, entered into an agreement with the Governor of the State of Michigan, the Attorney General of the State of Michigan, the Staff of2016, both the MPSC and the ownersPSCW approved the operation of two large minesUMERC, a subsidiary of WEC Energy Group, as a stand-alone utility in the Upper Peninsula of Michigan, to resolve all objections these parties raised atand UMERC became operational effective January 1, 2017. This utility holds the FERCelectric and MPSC related to Wisconsin Energy’s proposed acquisition of Integrys. We believe that this agreement isnatural gas distribution assets, previously held by WPS and us, located in the best interestUpper Peninsula of our customers. Michigan.

In connectionAugust 2016, WEC Energy Group entered into an agreement with Tilden, under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years, contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan.

In October 2017, the MPSC approved both the agreement we entered intowith Tilden and UMERC's application for a non-binding term sheetcertificate of necessity to sell our Michigan electric distribution assetsbegin construction of the proposed generation. The new units are expected to begin commercial operation in 2019 and the Presque Isle Power Plant to a third party. The carrying value of these assets is approximately $292 million as of December 31, 2014.
We are working to achieve a definitive agreementshould allow for the saleretirement of these assets by the end of March 2015. This agreement would be subject to approval by several regulatory agencies including FERC, the PSCW and the MPSC. If we are able to reach a definitive agreement consistent with the financial terms of the non-binding term sheet, we would seek the recovery of approximately $190 million of net unrecovered plant costs fromPIPP no later than 2020. Tilden will remain our remaining customers.customer until this new generation begins commercial operation.


2017 Form 10-K9689Wisconsin Electric Power Company
Table of Contents
2014 Form 10-K

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
2015 Wisconsin Electric Power Company:Rate Order

We have auditedIn May 2014, we applied to the accompanying consolidated balance sheetsPSCW for a biennial review of costs and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary (the "Company") as of rates. In December 31, 2014, and 2013, and the related consolidated income statements, statements of common equity, and statements of cash flows for each ofPSCW approved the three years in the period ended December 31, 2014. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.following rate adjustments, effective January 1, 2015:

We conducted
A net bill increase related to non-fuel costs for our auditsretail electric customers of approximately $2.7 million (0.1%) in accordance with2015. This amount reflected the standardsreceipt of the Public Company Accounting Oversight Board (United States). Those standards requireSSR payments from MISO that were higher than 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 wereanticipated when 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 appropriatefiled our rate request in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,May 2014, as well as evaluatingan offset of $26.6 million related to a refund of prior fuel costs and the overall financial statement presentation. We believeremainder of the proceeds from a Treasury Grant that we received in connection with our audits provide a reasonable basisbiomass 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 opinion.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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary as of December 31, 2014 and 2013Our authorized ROE was set at 10.2%, and our common equity component remained at an average of 51%. The PSCW order reaffirmed the resultsdeferral of their operationsour transmission costs, and their cash flowsit verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW order also authorized escrow accounting for eachSSR revenues because of the three yearsuncertainty 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 period ended December 31, 2014,difference is deferred and is expected to be recovered from customers with interest, 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.future rate case.

/s/DELOITTE & TOUCHE LLPEarnings Sharing Agreement

Milwaukee, WisconsinIn 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.
February 27, 2015
NOTE 22—QUARTERLY FINANCIAL INFORMATION (Unaudited)
(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total
2017          
Operating revenues $972.0
 $855.4
 $943.8
 $940.5
 $3,711.7
Operating income 185.1
 142.8
 163.4
 134.3
 625.6
Net income attributed to common shareholder 101.8
 75.3
 89.4
 69.1
 335.6
           
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

Due to various factors, the quarterly results of operations are not necessarily comparable.



2017 Form 10-K9790Wisconsin Electric Power Company
Table of Contents

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 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 have completed the review of our contracts with customers and are finalizing the related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We have evaluated the nature of our operating revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition. Most of our revenues are from regulated tariff sales, which are in the scope of the new standard, excluding the revenue component related to alternative revenue programs. The revenues from these contracts are recorded at the amount of the electricity or natural gas delivered to the customer during the period.

We adopted this standard for interim and annual periods beginning January 1, 2018, as required, and used the modified retrospective method of adoption. The most significant impact to the financial statements is expected to be in the form of additional disclosures. However, we do not expect to have a cumulative-effect adjustment to record on the balance sheet as of the beginning of 2018; and therefore, do not expect to include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance. We will include disaggregated revenue disclosures by segment, major products (electric and natural gas), and customer class in the combined notes to the financial statements, starting in the first quarter of 2018.

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. 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. As required, we adopted this ASU for interim and annual periods beginning January 1, 2018. We do not believe the adoption of this guidance will have a significant impact 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.

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 delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.


20142017 Form 10-K91Wisconsin Electric Power Company
Table of Contents

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. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. As required, we adopted this ASU for interim and annual periods beginning January 1, 2018 and used a retrospective transition method. We do not believe the adoption of this guidance will have a significant impact on our financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. As required, we adopted this ASU for interim and annual periods beginning January 1, 2018. The amendments will be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. As a result of the application of accounting principles for rate regulated entities, a similar amount of net benefit cost (including non-service components) will be recognized in our financial statements consistent with the current rate-making treatment. The impacts of adoption will be limited to changes in classification of non-service costs in the income statements.


2017 Form 10-K92Wisconsin Electric Power Company
Table of Contents

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


ITEM 9A.CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of Wisconsin Electric Power Company'sour internal control over financial reporting based on the framework in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that Wisconsin Electric Power Company'sour internal control over financial reporting was effective as of December 31, 2014.2017.

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 20142017 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.




2017 Form 10-K9893Wisconsin Electric Power Company
Table of Contents
2014 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",Directors," "Section 16(a) Beneficial Ownership Reporting Compliance",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 StockholdersShareholders to be held April 30, 201526, 2018 (the "2015"2018 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",Analysis," "Executive Compensation",Compensation," "Director Compensation",Compensation," "Committees of the WEC Energy Group Board of Directors -- Compensation",– Compensation," "Compensation Committee Report",Report," "Pay Ratio Disclosure," "Risk Analysis of Compensation Policies and Practices"Practices," and "Certain Relationships and Related Transactions --– Compensation Committee Interlocks and Insider Participation" in the 20152018 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 20152018 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.



99Wisconsin Electric Power Company
2014 Form 10-K

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information under "Corporate Governance -– Frequently Asked Questions: Who are the independent directors?,", "Corporate Governance -– Frequently Asked Questions: What are the WEC Energy Group Board's standards of independence?,", "Corporate Governance -– Frequently Asked Questions: Are the WEC Energy Group Audit and Oversight and Compensation Committees comprised solely of independent directors?,", "Corporate Governance -– Frequently Asked Questions: Does the Company have policies and procedures in place to review and approve related party transactions?," and "Certain Relationships and Related Transactions" in the 20152018 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.


2017 Form 10-K94Wisconsin Electric Power Company
Table of Contents

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 20152018 Annual Meeting Information Statement is incorporated herein by reference.


2017 Form 10-K95Wisconsin Electric Power Company
Table of Contents

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 Report of Independent Registered Public Accounting Firm Included in Part II of This Report
 Description Page in 10-K
    
 Consolidated Income Statements for the three years ended December 31, 2014.
Report of Independent Registered Public Accounting Firm.
 
6450
    
 
Consolidated Balance Sheets atIncome Statements for the three years ended December 31, 20142017, 2016, and 2013.2015.
 
6551
    
 
Consolidated Balance Sheets at December 31, 2017 and 2016.
52
Consolidated Statements of Cash Flows for the three years ended December 31, 2014.2017, 2016, and 2015.
 
6753
    
 
Consolidated Statements of Capitalization atEquity for the three years ended December 31, 20142017, 2016, and 2013.2015.
 
6854
    
 
Consolidated Statements of Common Equity for the three years endedCapitalization at December 31, 2014.2017 and 2016.
 
6955
    
 
Notes to Consolidated Financial Statements.
 
7056
2.Financial Statement Schedules Included in Part IV of This Report
    
 Report of Independent Registered Public Accounting Firm.
97

2
FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT
Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2014.2017, 2016, and 2015.
100
  
 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.


100Wisconsin Electric Power Company
2014 Form 10-K

3
EXHIBITS AND EXHIBIT INDEX
  
 See
3.Exhibits and Exhibit Index
The following exhibits are filed or furnished with or incorporated by reference in the Exhibit Index included as the last part of this report which is incorporated hereinwith respect to Wisconsin Electric Power Company (File No. 001-01245). An asterisk (*) indicates incorporation by reference.reference pursuant to Exchange Act Rule 12b-32. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 15(b) of Form 10-K is identified in the Exhibit Indexbelow by two asterisks (**) following the description of the exhibit.



101Wisconsin Electric Power Company
2014 Form 10-K

SCHEDULE IIVALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts Balance at Beginning of the Period Expense Deferral Net Write-offs Balance at End of the Period
  (Millions of Dollars)
December 31, 2014 $39.7
 $31.3
 $10.0
 $(34.2) $46.8
December 31, 2013 $36.7
 $31.4
 $2.7
 $(31.1) $39.7
December 31, 2012 $36.9
 $8.7
 $20.7
 $(29.6) $36.7



102Wisconsin Electric Power Company
2014 Form 10-K

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

WISCONSIN ELECTRIC POWER COMPANY
By  /s/GALE E. KLAPPA                                            
Date:February 27, 2015Gale E. Klappa, Chairman of the Board, President
and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/GALE E. KLAPPA                                                                  February 27, 2015
Gale E. Klappa, Chairman of the Board, President and Chief
Executive Officer and Director -- Principal Executive Officer
/s/J. PATRICK KEYESFebruary 27, 2015
J. Patrick Keyes, Executive Vice President and Chief
Financial Officer -- Principal Financial Officer
/s/STEPHEN P. DICKSON                                                         February 27, 2015
Stephen P. Dickson, Vice President and
Controller -- Principal Accounting Officer
/s/JOHN F. BERGSTROM                                                          February 27, 2015
John F. Bergstrom, Director
/s/BARBARA L. BOWLES                                                         February 27, 2015
Barbara L. Bowles, Director
/s/PATRICIA W. CHADWICK                                                   February 27, 2015
Patricia W. Chadwick, Director
/s/CURT S. CULVER                                                                   February 27, 2015
Curt S. Culver, Director
/s/THOMAS J. FISCHER                                                             February 27, 2015
Thomas J. Fischer, Director
/s/HENRY W. KNUEPPELFebruary 27, 2015
Henry W. Knueppel, Director
/s/ULICE PAYNE, JR.                                                                 February 27, 2015
Ulice Payne, Jr., Director
/s/MARY ELLEN STANEKFebruary 27, 2015
Mary Ellen Stanek, Director

103Wisconsin Electric Power Company
2014 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, 2014
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)

Number Exhibit
 
3 Articles of Incorporation and By-laws
    
  3.1*
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*
3.2*
Bylaws of Wisconsin Electric Power Company,WE, as amended to May 1, 2000. (Exhibit 3.1(3)-2 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*
4.1*
Reference is made to Article III of the Restated Articles of Incorporation of Wisconsin Electric Power Company. (ExhibitWE. (See Exhibit 3.1 herein.above.)
    
  Indentures and Securities Resolutions:
    
  4.2*
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*
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.)

2017 Form 10-K96Wisconsin Electric Power Company
Table of Contents

NumberExhibit
4.4*
Securities Resolution No. 3 of WE under the WE Indenture, dated May 27, 1998. (Exhibit (4)-1 to WE's 06/30/98 Form 10-Q.)
    
  4.4*Securities Resolution No. 3 of Wisconsin Electric under the Wisconsin Electric Indenture, dated May 27, 1998. (Exhibit (4)-1 to Wisconsin Electric's 06/30/98 Form 10-Q.)
4.5*
4.5*
Securities Resolution No. 5 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of 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*
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. 9 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2008. (Exhibit 4.1 to Wisconsin Electric's 12/08/08 Form 8-K.)
4.7*

E-1Wisconsin Electric Power Company
2014 Form 10-K

NumberExhibit
4.8*Securities Resolution No. 10 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of December 8, 2009. (Exhibit 4.1 to Wisconsin Electric'sWE's 12/08/09 Form 8-K.)
    
  4.9*
4.8*
Securities Resolution No. 11 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of September 7, 2011. (Exhibit 4.1 to Wisconsin Electric'sWE's 09/07/11 Form 8-K.)
    
  4.10*
4.9*
Securities Resolution No. 12 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of December 5, 2012. (Exhibit 4.1 to Wisconsin Electric'sWE's 12/05/12 Form 8-K.)
    
  4.11*
4.10*
Securities Resolution No. 13 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of June 10, 2013. (Exhibit 4.1 to Wisconsin Electric’sWE’s 06/10/13 Form 8-K.)
    
  4.12*
4.11*
Securities Resolution No. 14 of Wisconsin ElectricWE under the Wisconsin ElectricWE Indenture, dated as of May 12, 2014. (Exhibit 4.1 to Wisconsin Electric'sWE'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.)
4.13*
Securities Resolution No. 16 of WE under the WE Indenture, dated as of November 13, 2015. (Exhibit 4.1 to WE'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*Wisconsin
10.1*
WEC Energy CorporationGroup Supplemental Pension Plan, Amended and Restated Effective as of January 1, 2015.2017. (Exhibit 10.1 to WisconsinWEC Energy Corporation'sGroup's 12/31/201416 Form 10-K (File No. 001-09057).)** See Note.
    
  10.2*Service Agreement, dated April 25, 2000, between Wisconsin Electric Power Company and Wisconsin Gas LLC. (Exhibit 10.32 to Wisconsin
10.2*
Legacy 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*Legacy Wisconsin Energy CorporationGroup Executive Deferred Compensation Plan, Amended and Restated as of January 1, 2015.2016. (Exhibit 10.410.2 to WisconsinWEC Energy Corporation'sGroup's 12/31/201415 Form 10-K (File No. 001-09057).)** See NoteNote.
    
  10.5*Wisconsin
10.3*
WEC Energy CorporationGroup Executive Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2015.2017. (Exhibit 10.510.3 to WisconsinWEC Energy Corporation'sGroup's 12/31/201416 Form 10-K (File No. 001-09057).)** See Note.
    
  10.6*Directors' Deferred Compensation
10.4*
WEC Energy Group Non-Qualified Retirement Savings Plan, of Wisconsin Energy Corporation, as amendedAmended and restatedRestated Effective as of MayJanuary 1, 2004 (the "Legacy DDCP").2017. (Exhibit 10.310.6 to WisconsinWEC Energy Corporation's 06/30/04Group's 12/31/16 Form 10-Q10-K (File No. 001-09057).)** See Note.
    
  10.7*First Amendment to the Legacy DDCP, effective as of January 1, 2005. (Exhibit 10.15 to Wisconsin
10.5*
WEC Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

E-2Wisconsin Electric Power Company
2014 Form 10-K

NumberExhibit
10.8*Wisconsin Energy Corporation Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2015. (Exhibit 10.8 to Wisconsin Energy Corporation's 12/31/2014 Form 10-K (File No. 001-09057).)** See Note.
10.9*Wisconsin Energy Corporation Non-Qualified Retirement Savings Plan, Effective January 1, 2015. (Exhibit 10.9 to Wisconsin Energy Corporation's 12/31/2014 Form 10-K (File No. 001-09057).)** See Note.
10.10*Wisconsin Energy Corporation Death Benefit Only Plan, as amended and restated as of July 22, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/10 Form 10-Q (File No. 001-09057).)** See Note.
10.11*Wisconsin Energy CorporationGroup Short-Term Performance Plan, as amended and restated effective as of January 1, 2010.2016. (Exhibit 10.110.2 to WisconsinWEC Energy Corporation'sGroup's 12/03/0915 Form 8-K (File No. 001-09057).)** See Note.
    
  10.12*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.
10.6*
10.13*
Wisconsin Energy Corporation 2014 Rabbi Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 23, 2015, regarding the trust established to provide a source of funds to assist in meeting the liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.13 to Wisconsin Energy Corporation's 12/31/14 Form 10-K (File No. 001-09057).)** See Note.
    
  10.14*Affiliated Interest
10.7*
Letter Agreement (Service Agreement), dated December 12, 2002, by and among Wisconsinbetween WEC Energy CorporationGroup, Inc. and its affiliates.Gale E. Klappa, dated as of December 7, 2017. (Exhibit 10.1410.1 to WisconsinWEC Energy Corporation'sGroup's 12/31/0208/17 Form 10-K8-K. (File No. 001-09057).) ** See Note.

2017 Form 10-K97Wisconsin Electric Power Company
Table of Contents

NumberExhibit
    
  10.15*Amended
10.8*
Terms and Restated Senior Officer Employment and Non-Compete Agreement between WisconsinConditions Governing Gale Klappa's Restricted Stock Award Under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.2 to WEC Energy Corporation and Gale E. Klappa, dated as of December 29, 2008. (Exhibit 10.25 to Wisconsin Energy Corporation'sGroup's 12/31/0808/17 Form 10-K8-K. (File No. 001-09057).)** See Note.
    
  10.16*
10.9*
Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Allen L. Leverett, dated as of December 30, 2008. (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.
    
  10.17*Terms of Employment for J. Patrick Keyes. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/12 Form 10-Q (File No. 001-09057).)** See Note.
10.10*
10.18*Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of December 20, 2010. (Exhibit 10.20 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.
10.19*Amendment to the Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of August 15, 2011. (Exhibit 10.21 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.

E-3Wisconsin Electric Power Company
2014 Form 10-K

NumberExhibit
10.20*Terms of Employment for Susan H. Martin. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/12 Form 10-Q (File No. 001-09057).)**See Note.
    
  10.21*Supplemental Pension Benefit agreement between Wisconsin Energy Corporation and Stephen Dickson, effective May 23, 2001. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/01 Form 10-Q (File No. 001-09057).)** See Note.
10.22*Amendment to the Supplemental Pension Benefit Agreement between Wisconsin Energy Corporation and Stephen P. Dickson, dated December 29, 2008. (Exhibit 10.32 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.
10.23*Amended and Restated Non-Compete and Special Severance Tax Protection Agreement between Wisconsin Energy Corporation and Stephen P. Dickson, effective as of January 1, 2008. (Exhibit 10.33 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.
10.24*
10.11*
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.
    
  10.25*
10.12*
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.
    
  10.26*1993 Omnibus Stock Incentive Plan, amended
10.13*
Letter Agreement by and restated effectivebetween WEC Energy Group, Inc. and Margaret C. Kelsey, dated as of May 5, 2011, as approved by Wisconsin Energy Corporation's stockholders at its 2011 annual meeting of stockholders.July 19, 2017. (Exhibit 10.1 to WisconsinWEC Energy Corporation's 06/Group's 09/30/1117 Form 10-Q10-Q. (File No. 001-09057).)** See Note.
    
  10.27*2005 Terms and Conditions Governing Non-Qualified Stock Option Award under
10.14*
1993 Omnibus Stock Incentive Plan.Plan, Amended and Restated Effective as of January 1, 2016. (Exhibit 10.110.19 to WisconsinWEC Energy Corporation'sGroup's 12/28/0431/15 Form 8-K10-K (File No. 001-09057).)** See Note.
    
  10.28*
10.15*
Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/07 Form 10-Q (File No. 001-09057).)** See Note.
    
  10.29*Terms and Conditions Governing Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan, approved December 1, 2010. (Exhibit 10.1 to Wisconsin
10.16*
WEC Energy Corporation's 12/01/10 Form 8-K (File No. 001-09057).)** See Note.
10.30*Wisconsin Energy Corporation Terms and Conditions Governing Director Restricted Stock Award under the 1993 Omnibus Stock Incentive Plan, amended and restated effective May 5, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 01/19/12 Form 8-K (File No. 001-09057).)** See Note.
10.31*Wisconsin Energy CorporationGroup Performance Unit Plan, amended and restated effective as of January 1, 2015.2017. (Exhibit 10.1 to WisconsinWEC Energy Corporation'sGroup's 12/04/1401/16 Form 8-K (File No. 001-09057).)** See Note.
    
  10.32*Form of Award of Performance Units under the Wisconsin
10.17*
2016 WEC Energy Corporation Performance Unit Plan. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/06/04 Form 8-K (File No. 001-09057).)** See Note.

E-4Wisconsin Electric Power Company
2014 Form 10-K

NumberExhibit
10.33*Wisconsin Energy CorporationGroup Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014.Plan. (Exhibit 10.210.27 to WisconsinWEC Energy Corporation'sGroup’s 12/04/1431/15 Form 8-K10-K (File No. 001-09057).)** See Note.
    
  10.34*
10.18*
Wisconsin Energy Corporation Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 OmnibousOmnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.
    
  10.35*
10.19*
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.
10.20*
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.)
    
  10.36*
10.21*
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.)
    
  10.37*
10.22*
Elm Road I Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)
    
  10.38*
10.23*
Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)
    
  10.39*
10.24*
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).)

    

2017 Form 10-K98Wisconsin Electric Power Company
Table of Contents

NumberExhibit
  10.40*
10.25*
Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC, dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K (File No. 001-09057).)
    
  Note:  Two asterisks (**) identify management contracts
10.26*
Terms and executive compensation plans or arrangements requiredConditions for July 31, 2015 Special Restricted Stock Award. (Exhibit 10.1 to be filed as exhibits pursuant to Item 15(b) ofWEC Energy Group’s 6/30/15 Form 10-K.10-Q (File No. 001-09057).)** See Note.
   
21
 Subsidiaries of the registrant
    
  21.1
21.1
Subsidiaries of Wisconsin Electric Power Company.
    
23
 Consents of experts and counsel
    
  23.1Deloitte & Touche LLP - Milwaukee, WI,
23.1
Consent of Independent Registered Public Accounting Firm.Firm for WE.
    
 

E-5Wisconsin Electric Power Company
2014 Form 10-K

NumberExhibit
31
 Rule 13a-14(a)/15d-14(a) Certifications
    
  31.1
31.1
Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
    
  31.2
31.2
Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
    
32
 Section 1350 Certifications
    
  32.1
32.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
    
  32.2
32.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
    
101
 Interactive Data File

ITEM 16. FORM 10-K SUMMARY

None.


2017 Form 10-KE-699Wisconsin Electric Power Company
Table of Contents

SCHEDULE II
WISCONSIN ELECTRIC POWER COMPANY
VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts
(in millions)
 Balance at Beginning of Period 
Transfer of Net Assets to UMERC (1)
 
Expense (2)
 Deferral 
Net Write-offs (3)
 Balance at End of Period
December 31, 2017 $40.9
 $(0.3) $31.2
 $(6.4) $(25.9) $39.5
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

(1)
See Note 4, Related Parties, for more information.

(2)
Net of recoveries

(3)
Represents amounts written off to the reserve, net of adjustments to regulatory assets.

2017 Form 10-K100Wisconsin Electric Power Company
Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

WISCONSIN ELECTRIC POWER COMPANY
By  /s/ GALE E. KLAPPA
Date:February 28, 2018Gale E. Klappa, Chairman of the Board and
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/ GALE E. KLAPPAFebruary 28, 2018
Gale E. Klappa, Chairman of the Board and Chief Executive
Officer and Director -- Principal Executive Officer
/s/ SCOTT J. LAUBERFebruary 28, 2018
Scott J. Lauber, Executive Vice President and Chief
Financial Officer and Director -- Principal Financial Officer
/s/ WILLIAM J. GUCFebruary 28, 2018
William J. Guc, Vice President and
Controller -- Principal Accounting Officer
/s/ J. KEVIN FLETCHERFebruary 28, 2018
J. Kevin Fletcher, Director
/s/ MARGARET C. KELSEYFebruary 28, 2018
Margaret C. Kelsey, Director
/s/ TOM METCALFEFebruary 28, 2018
Tom Metcalfe, Director


2017 Form 10-K101Wisconsin Electric Power Company