WISCONSIN ELECTRIC POWER CO - Annual Report: 2016 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2016



[ ]	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.

001-01245	WISCONSIN ELECTRIC POWER COMPANY	39-0476280
	(A Wisconsin Corporation) 231 West Michigan Street P. O. Box 2046 Milwaukee, WI 53201 414-221-2345

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

None

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



Serial Preferred Stock, 3.60% Series, $100 Par Value
Six Per Cent. Preferred Stock, $100 Par Value

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

Yes [ ] No [X]

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

Yes [ ] No [X]

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate 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) is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



	Large accelerated filer [ ]	Accelerated filer [ ]
	Non-accelerated filer [X]	Smaller reporting company [ ]

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ] No [X]

As of June 30, 2016 (and currently), all of the common stock of Wisconsin Electric Power Company is held by WEC Energy Group, Inc.



	State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant.

None.



	Number of shares outstanding of each class of common stock, as of
	January 31, 2017

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

Documents incorporated by reference:

Portions of Wisconsin Electric Power Company's Definitive information statement on Schedule 14C for its Annual Meeting of Stockholders, to be held on April 27, 2017, are incorporated by reference into Part III hereof.

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY

ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2016

TABLE OF CONTENTS



					Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION					1
PART I					3
ITEM 1.	BUSINESS				3
	A.	INTRODUCTION			3
	B.	UTILITY SEGMENT			3
	C.	OTHER SEGMENT			12
	D.	REGULATION			12
	E.	ENVIRONMENTAL COMPLIANCE			15
	F.	EMPLOYEES			15
ITEM 1A.	RISK FACTORS				16
ITEM 1B.	UNRESOLVED STAFF COMMENTS				24
ITEM 2.	PROPERTIES				25
ITEM 3.	LEGAL PROCEEDINGS				26
ITEM 4.	MINE SAFETY DISCLOSURES				26
	EXECUTIVE OFFICERS OF THE REGISTRANT				27
PART II					28
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES				28
ITEM 6.	SELECTED FINANCIAL DATA				29
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				30
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				46
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA				47
	A.	Report of Independent Registered Public Accounting Firm			47
	B.	Consolidated Income Statements			48
	C.	Consolidated Balance Sheets			49
	D.	Consolidated Statements of Cash Flows			50
	E.	Consolidated Statements of Equity			51
	F.	Consolidated Statements of Capitalization			52
	G.	Notes to Consolidated Financial Statements			53
		Note 1	Summary of Significant Accounting Policies	53
		Note 2	Acquisitions	58
		Note 3	Dispositions	59
		Note 4	Related Parties	59
		Note 5	Investment in American Transmission Company	61
		Note 6	Supplemental Cash Flow Information	62
		Note 7	Regulatory Assets and Liabilities	62
		Note 8	Property, Plant, and Equipment	63
		Note 9	Asset Retirement Obligations	63
		Note 10	Common Equity	64
		Note 11	Preferred Stock	66
		Note 12	Short-Term Debt and Lines of Credit	66
		Note 13	Long-Term Debt and Capital Lease Obligations	67
		Note 14	Income Taxes	69
		Note 15	Employee Benefits	71
		Note 16	Commitments and Contingencies	76
		Note 17	Fair Value Measurements	81
		Note 18	Derivative Instruments	82



2016 Form 10-K	i	Wisconsin Electric Power Company

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		Note 19	Variable Interest Entities	83
		Note 20	Regulatory Environment	84
		Note 21	Segment Information	85
		Note 22	Quarterly Financial Information (Unaudited)	86
		Note 23	New Accounting Pronouncements	86
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE				89
ITEM 9A.	CONTROLS AND PROCEDURES				89
ITEM 9B.	OTHER INFORMATION				89
PART III					90
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT				90
ITEM 11.	EXECUTIVE COMPENSATION				90
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS				90
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE				90
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES				91
PART IV					92
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES				92
ITEM 16.	FORM 10-K SUMMARY				92
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS					93
SIGNATURES					94
EXHIBIT INDEX					95



2016 Form 10-K	ii	Wisconsin Electric Power Company

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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:



Subsidiaries and Affiliates
ATC		American Transmission Company LLC
Bostco		Bostco LLC
Integrys		Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
UMERC		Upper Michigan Energy Resources Corporation
WBS		WEC Business Services LLC
WE		Wisconsin Electric Power Company
We Power		W.E. Power, LLC
WEC Energy Group		WEC Energy Group, Inc. (previously known as Wisconsin Energy Corporation)
WG		Wisconsin Gas LLC
WPS		Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
ARO		Asset Retirement Obligation
ASC		Accounting Standards Codification
ASU		Accounting Standards Update
CWIP		Construction Work in Progress
FASB		Financial Accounting Standards Board
GAAP		Generally Accepted Accounting Principles
OPEB		Other Postretirement Employee Benefits

Environmental Terms
Act 141		2005 Wisconsin Act 141
CO₂		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
GHG		Greenhouse Gas
MATS		Mercury and Air Toxics Standards
NAAQS		National Ambient Air Quality Standards
NOx		Nitrogen Oxide
SO₂		Sulfur Dioxide

Measurements
Dth		Dekatherm (One Dth equals one million Btu)
MW		Megawatt (One MW equals one million Watts)
MWh		Megawatt-hour



2016 Form 10-K	iii	Wisconsin Electric Power Company

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Other Terms and Abbreviations
AIA		Affiliated Interest Agreement
ALJ		Administrative Law Judge
ARRs		Auction Revenue Rights
Compensation Committee		Compensation Committee of the Board of Directors of WEC Energy Group, Inc.
D.C. Circuit Court of Appeals		United States Court of Appeals for the District of Columbia
ERGS		Elm Road Generating Station
ER 1		Elm Road Generating Station Unit 1
ER 2		Elm Road Generating Station Unit 2
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
GCRM		Gas Cost Recovery Mechanism
LMP		Locational Marginal Price
MCPP		Milwaukee County Power Plant
Merger Agreement		Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Market
NYMEX		New York Mercantile Exchange
OCPP		Oak Creek Power Plant
OC 5		Oak Creek Power Plant Unit 5
OC 6		Oak Creek Power Plant Unit 6
OC 7		Oak Creek Power Plant Unit 7
OC 8		Oak Creek Power Plant Unit 8
Omnibus Stock Incentive Plan		WEC Energy Group 1993 Omnibus Stock Incentive Plan, Amended and Restated Effective as of January 1, 2016
PIPP		Presque Isle Power Plant
Point Beach		Point Beach Nuclear Power Plant
PWGS		Port Washington Generating Station
PWGS 1		Port Washington Generating Station Unit 1
PWGS 2		Port Washington Generating Station Unit 2
ROE		Return on Equity
RTO		Regional Transmission Organization
SSR		System Support Resource
Supreme Court		United States Supreme Court
Treasury Grant		Section 1603 Renewable Energy Treasury Grant
VAPP		Valley Power Plant



2016 Form 10-K	iv	Wisconsin Electric Power Company

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning 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 Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-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 regulations 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 a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in Item 1A. Risk Factors and those identified below:


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


•	Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic 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 and 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 increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;


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

•

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


•	Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental 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;

•

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 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, or other developments;


•	Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;


•	Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;


•	The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;



2016 Form 10-K	1	Wisconsin Electric Power Company

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


•	The direct or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber security intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;


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


•	Factors affecting the 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 Wisconsin Energy Corporation's acquisition of Integrys;


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


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


•	Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

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



2016 Form 10-K	2	Wisconsin Electric Power Company

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PART I

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 WEC Energy Group and were incorporated in the state of Wisconsin in 1896. We maintain our principal executive offices in Milwaukee, Wisconsin and serve customers in Wisconsin and served customers in the Upper Peninsula of Michigan through December 31, 2016. Effective January 1, 2017, we transferred our electric customers and distribution assets located in the Upper Peninsula of Michigan to UMERC, a stand-alone utility. UMERC became operational effective January 1, 2017. See Note 20, Regulatory Environment, for more information on UMERC. Our two reportable segments are utility and other. Bostco is our non-utility subsidiary that develops and invests in real estate.

For more information about our utility operations, including financial and geographic information, see Note 21, Segment Information, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

Acquisition

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

Available Information

Our annual and periodic filings with the SEC are available, free of charge, through WEC Energy Group's website, www.wecenergygroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC.

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

B. UTILITY 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 southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin.

Through December 31, 2016, we serviced electric customers in the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred our electric customers and electric distribution assets located in the Upper Peninsula of Michigan to UMERC, a new stand-alone utility owned by WEC Energy Group. UMERC obtains its energy through the MISO Energy Markets and meets its obligations through power purchase agreements with us and WPS. See Note 4, Related Parties, and Note 20, Regulatory Environment, for more information. We continue to serve an iron ore mine owned by Tilden Mining Company (Tilden) in the Upper Peninsula of Michigan. For more information on the mine, see the discussion under the heading "Large Electric Retail Customers."



2016 Form 10-K	3	Wisconsin Electric Power Company

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Operating Revenues

The following table shows electric utility operating revenues, including steam operations, for the past three years:



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


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


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

Electric Sales

Our electric energy deliveries included supply and distribution sales to retail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier. In 2016, retail electric revenues accounted for 87.5% of total electric operating revenues, while wholesale and resale electric revenues accounted for 9.1% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Utility Segment Contribution to Operating Income for information on MWh 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 and boundary agreements with other utilities. Through December 31, 2016, we were authorized to provide electric service in certain territories in the state of Michigan pursuant to franchises granted by municipalities. We will continue to provide service to the Tilden mine located in the Upper Peninsula of Michigan pursuant to a contract between Tilden and us until UMERC's proposed generation begins commercial operation. See Note 20, Regulatory Environment, for more information.

We buy and sell wholesale electric power by participating in the MISO Energy Markets. The cost of our individual generation offered into the MISO Energy Markets, compared to our competitors, affects how often our generating units are dispatched and how we buy and sell power. For more information, see Item 1. Business – D. Regulation.

Steam Sales

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

Electric Sales Forecast

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



2016 Form 10-K	4	Wisconsin Electric Power Company

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Customers



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

Electric customers – average	1,143.1	1,136.5	1,130.7
Steam customers – average	0.4	0.4	0.4

Large Electric Retail Customers

We provide electric utility service to a diversified base of customers in such industries as governmental, mining, food products, health services, foundry, paper, printing, and retail. In February 2015, our largest retail electric customers, two iron ore mines located in the Upper Peninsula of Michigan, returned as customers after choosing an alternative electric supplier in September 2013. For more information on alternative electric suppliers, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Industry Restructuring. We entered into a contract with each of the mines to provide full requirements electric service through December 31, 2019. Since 2015, we have been deferring, and expect to continue to defer the revenue less cost of sales, from the mine sales and will apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding.

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

Wholesale Customers

We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers. Wholesale sales accounted for 3.2%, 3.4%, and 5.3% of total electric energy sales during 2016, 2015, and 2014, respectively. Wholesale revenues accounted for 2.6%, 2.9%, and 3.8% of total electric operating revenues during 2016, 2015, and 2014, respectively.

Resale

The majority of our sales for resale are sold to one RTO, MISO, at market rates based on availability of our generation and RTO demand. Resale sales accounted for 23.0%, 23.8%, and 18.5% of total electric energy sales during 2016, 2015, and 2014, respectively. Resale revenues accounted for 6.5%, 6.6%, and 7.7% of total electric operating revenues during 2016, 2015, and 2014, respectively. Retail fuel costs are reduced by the amount that revenue exceeds the costs of sales derived from these opportunity sales.

Electric Generation and Supply Mix

Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to maintain a stable, reliable, and affordable supply of electricity. Through 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 from We Power. We supplement our internally generated power supply with long-term power purchase agreements, including the Point Beach power purchase agreement discussed under the heading "Power Purchase Commitments," and through spot purchases in the MISO Energy Markets. We also sell excess capacity into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power.



2016 Form 10-K	5	Wisconsin Electric Power Company

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Our rated capacity by fuel type, including the units we lease from We Power, as of December 31 is shown below. For more information on our electric generation facilities, see Item 2. Properties.



	Rated Capacity in MW ⁽¹⁾
	2016	2015	2014
Coal	3,582	3,589	3,707
Natural gas:
Combined cycle	1,140	1,082	1,082
Steam turbine ⁽²⁾	240	240	118
Natural gas/oil peaking units ⁽³⁾	962	962	962
Renewables ⁽⁴⁾	190	187	155
Total rated capacity	6,114	6,060	6,024


⁽¹⁾	Rated 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, 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.


⁽²⁾	The natural gas steam turbine represents the rated capacity associated with the VAPP Units, which were converted from coal to natural gas in 2014 and 2015.


⁽³⁾	The dual-fueled facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local natural gas distribution company that delivers natural gas to the plants.


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

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2017:



	Estimate		Actual
	2017		2016		2015		2014
Company-owned or leased generation units:
Coal	52.5	%	49.9	%	53.5	%	55.2	%
Natural gas:
Combined cycle	10.4	%	15.9	%	13.0	%	8.7	%
Steam turbine	1.0	%	1.2	%	1.4	%	0.2	%
Natural gas/oil peaking units	0.1	%	0.7	%	0.6	%	0.2	%
Renewables	3.9	%	3.5	%	3.5	%	3.8	%
Total company-owned or leased generation units	67.9	%	71.2	%	72.0	%	68.1	%
Power purchase contracts:
Nuclear	25.6	%	24.6	%	24.5	%	25.4	%
Natural gas	1.9	%	2.4	%	1.7	%	2.1	%
Renewables	2.1	%	1.8	%	1.1	%	2.7	%
Other	0.1	%	—	%	0.7	%	0.9	%
Total power purchase contracts	29.7	%	28.8	%	28.0	%	31.1	%
Purchased power from MISO	2.4	%	—	%	—	%	0.8	%
Total purchased power	32.1	%	28.8	%	28.0	%	31.9	%
Total electric utility supply	100.0	%	100.0	%	100.0	%	100.0	%

Coal-Fired Generation

Our coal-fired generation, including the units we lease from We Power, consists of four operating plants with a rated capacity of 3,582 MW as of December 31, 2016. For more information about our operating plants, see Item 2. Properties.

Natural Gas-Fired Generation

Our natural gas-fired generation, including the units we lease from We Power, consists of four operating plants, including peaking units, with a rated capacity of 2,162 MW as of December 31, 2016. For more information about our operating plants, see Item 2. Properties.



2016 Form 10-K	6	Wisconsin Electric Power Company

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Oil-Fired Generation

Fuel oil is used for combustion turbines at certain of our natural gas-fired plants as well as for ignition and flame stabilization at one of our coal-fired plants. Our oil-fired generation had a rated capacity of 180 MW as of December 31, 2016. We also have natural gas-fired peaking units with a rated capacity of 782 MW, which have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our operating plants, see Item 2. Properties.

Renewable Generation

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

Hydroelectric

Our hydroelectric generating system consists of 13 operating plants with both a total installed capacity and a rated capacity of 89 MW as of December 31, 2016. All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Wind

We have four wind sites, consisting of 200 turbines, with an installed capacity of 339 MW and a rated capacity of 51 MW as of December 31, 2016.

Biomass

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

Generation from Leased We Power Units

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

Electric System Reliability

The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. In 2008, the PSCW established a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO has a 15.2% reserve margin requirement for the planning year from June 1, 2016, through May 31, 2017. Although MISO's short-term reserve margin changes from year-to-year, fluctuations are typically less than 0.5%. The MPSC does not have minimum guidelines for future supply reserves.

We had adequate capacity through company-owned generation units, leased generating units, and power purchase contracts to meet the MISO calculated planning reserve margin during 2016 and expect to have adequate capacity to meet the planning reserve margin requirements during 2017. 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.



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Fuel and Purchased Power Costs

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. For more information about the fuel rules, see Item 1. Business – D. Regulation.

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



	2016		2015		2014
Coal	$	22.68	$	25.25	$	27.68
Natural gas combined cycle	19.13		23.44		40.64
Natural gas/oil peaking units	46.99		56.33		129.83
Purchased power	43.51		43.87		47.47

We purchase coal under long-term contracts, which helps with price stability. Coal and associated transportation services have continued to see volatility in pricing due to changing domestic and world-wide demand for coal and the impacts of diesel costs, which are incorporated into fuel surcharges on rail transportation. 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 purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage.

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

Coal Supply

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

The annual tonnage amounts contracted for the next three years are as follows:



(in thousands)		Annual Tonnage
2017		7,934
2018		6,120
2019		3,132

Coal Deliveries

All of our 2017 coal requirements are expected to be shipped by our owned or leased unit trains under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming, Pennsylvania, and Montana. The coal is transported by train to our rail-served electric-generating facilities and to dock storage in Superior, Wisconsin, until needed by our lake vessel-served facilities. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.

Midcontinent Independent System Operator Costs

In connection with its status as a FERC approved RTO, MISO developed and operates the MISO Energy Markets, which include its bid-based energy markets and ancillary services market. We are a participant in the MISO Energy Markets. For more information on MISO, see Item 1. Business – D. Regulation.



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Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. As of December 31, 2016, our power purchase commitments with unaffiliated parties for the next five years are 1,279 MW per year. This amount includes 1,033 MW per year related to a long-term power purchase agreement for electricity generated by Point Beach.

Other Matters

Seasonality

Our electric utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. Our generating plants performed as expected during the warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, we did not require public appeals for conservation, and we did not interrupt or curtail service to non-firm customers who participate in load management programs.

Competition

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

For more information on competition in our service territories, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Industry Restructuring.

Environmental Matters

For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 16, Commitments and Contingencies.

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 and boundary agreements with other utilities. We also transport customer-owned natural gas. We operate in three distinct service areas including west and south of the City of Milwaukee, the Appleton area, and areas within Iron and Vilas Counties, Wisconsin.



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Natural Gas Utility Operating Statistics

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



	Year Ended December 31
	2016			2015		2014
Operating revenues (in millions)
Residential	$	238.6		$	256.6	$	390.5
Commercial and industrial	105.0			118.9		204.5
Total retail revenues	343.6			375.5		595.0
Transport	13.6			16.0		16.8
Other operating revenues *	(5.0		)	8.2		2.4
Total	$	352.2		$	399.7	$	614.2

Customers – end of year (in thousands)
Residential	442.0			438.7		435.6
Commercial and industrial	39.4			39.1		38.9
Transport	0.7			0.7		0.6
Total customers	482.1			478.5		475.1

Customers – average (in thousands)	480.1			476.4		472.6


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

Natural Gas Deliveries

Our gas therm deliveries include customer-owned transported natural gas. Transported natural gas accounted for approximately 38.0% of the total volumes delivered during 2016, 36.4% during 2015, and 33.7% during 2014. Our peak daily send-out during 2016 was 7.0 million therms on January 18, 2016.

Large Natural Gas 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, food products, education, metals, and real estate.

Natural Gas Sales Forecast

Our service territory experienced growth in weather-normalized retail natural gas deliveries (excluding natural gas deliveries for electric generation) in 2016 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 rate between flat and 0.5% over the next five years, assuming normal weather. The forecast projects positive customer growth being offset by energy efficiency.

Natural Gas Supply, Pipeline Capacity and Storage

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

Pipeline Capacity and Storage

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

Due to the daily and seasonal variations in natural gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage inventory levels at approximately 35% of forecasted winter demand; November through March is considered the winter season. Storage capacity, along with our natural gas purchase contracts, enables



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us to manage significant changes in daily demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months when demand is lower and withdraw it in the winter months. As a result, we can contract for less long-line pipeline capacity during periods of peak usage than would otherwise be necessary and can purchase natural gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.

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

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

Term Natural Gas Supply

We have contracts for firm supplies with terms of 3–5 months with suppliers for natural gas acquired in the Chicago, Illinois market hub and in the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices.

Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our forecasted design peak-day throughput is 9.6 million therms for the 2016 through 2017 heating season.

Secondary Market Transactions

Pipeline and storage capacity and natural gas supplies under contract can be resold in secondary markets. Local distribution companies, like our natural gas operations, must contract for capacity and supply sufficient to meet the firm peak-day demand of their customers. Peak or near peak demand days generally occur only a few times each year. The secondary markets facilitate higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and natural gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to customers, subject to our approved GCRM. During 2016, we continued to participate in the secondary markets. For information on our GCRM, see Note 1(d), Revenues and Customer Receivables.

Spot Market Natural Gas Supply

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

Hedging Natural Gas Supply Prices

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

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

Seasonality

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



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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

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

American Transmission Company

ATC is a regional transmission company that owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Minnesota. ATC is expected to provide comparable service to all customers, including us, and to support effective competition in energy markets without favoring any market participant. ATC is regulated by the FERC for all rate terms and conditions of 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. As of December 31, 2016, our ownership interest in ATC was approximately 23%; however, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information.

ATC is currently named in a complaint filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints, for more information.

D. REGULATION

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

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



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Rates

Our rates are regulated by the various commissions shown in the table below. These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.



Regulated Rates		Regulatory Commission
Retail electric, natural gas, and steam		PSCW
Retail electric		MPSC *
Wholesale power		FERC


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

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

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

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

For information on how our rates are set, see Note 20, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:



Regulatory Commission		Website
PSCW		https://psc.wi.gov/
MPSC		http://www.michigan.gov/mpsc/
FERC		http://www.ferc.gov/

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

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



	2016				2015				2014
(in millions)	Amount		Percent		Amount		Percent		Amount		Percent
Electric
Wisconsin	$	2,973.3	86.4	%	$	2,961.9	85.7	%	$	2,990.4	86.8	%
Michigan	154.2		4.5	%	163.0		4.7	%	58.8		1.7	%
FERC – Wholesale	313.1		9.1	%	329.5		9.6	%	396.0		11.5	%
Total	3,440.6		100.0	%	3,454.4		100.0	%	3,445.2		100.0	%

Natural Gas – Wisconsin	352.2		100.0	%	399.7		100.0	%	614.2		100.0	%

Total utility operating revenues	$	3,792.8			$	3,854.1			$	4,059.4



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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.

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

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

Other Electric Regulations

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

We are subject to Act 141 in Wisconsin and Public Acts 295 and 342 in Michigan, which contain certain minimum requirements for renewable energy generation. See Note 16, 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 natural gas we distribute 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 state commissions 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 provide natural gas service and grant credit (with applicable deposit requirements) to customers within our service territory. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs that provide for a limited amount of funding for assistance to our low-income customers.



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E. ENVIRONMENTAL COMPLIANCE

Our operations are subject to extensive environmental regulation 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 regulations or revisions to existing laws, including for example, additional regulation of GHG 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. For a discussion of matters related to manufactured gas plant sites and air and water quality, see Note 16, Commitments and Contingencies.

F. EMPLOYEES

As of December 31, 2016, we had 3,099 employees, of which 3,021 were full-time.

As of December 31, 2016, we had employees represented under labor agreements with the following bargaining units:



	Number of Employees	Expiration Date of Current Labor Agreement
Local 2150 of International Brotherhood of Electrical Workers, AFL-CIO	1,667	August 15, 2017
Local 420 of International Union of Operating Engineers, AFL-CIO	458	September 30, 2017
Local 2006 Unit 1 of United Steel Workers of America, AFL-CIO	119	April 30, 2017
Local 510 of International Brotherhood of Electrical Workers, AFL-CIO	106	October 31, 2020
Total	2,350



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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, including regulation by the PSCW, MPSC, and the FERC. This regulation significantly influences our operating environment and may affect our ability to recover costs from utility customers. Many aspects of our operations are regulated, including, but not limited to: the rates we charge our retail electric, natural gas, and steam customers; wholesale power service practices; electric reliability requirements and accounting; participation in the interstate natural gas pipeline capacity market; standards of service; issuance of securities; short-term debt obligations; construction and operation of facilities; transactions with affiliates; and billing practices. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs. Failure to comply with any applicable rules or regulations may lead to customer refunds, penalties, and other payments, which could materially and adversely affect our results of operations and financial condition.

The rates we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Rate regulation is based on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent on regulatory action, and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable 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 recognized in current period expense and could have a material adverse impact on our results of operations, cash flows, and financial condition.

We believe we have obtained the necessary permits, approvals, authorizations, certificates, and licenses for our existing operations, have complied with all of their associated terms, and that our business is conducted in accordance with applicable laws. These permits, approvals, authorizations, certificates, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies. Changes in regulations, interpretations of regulations, or the imposition of new regulations could influence our operating environment, may result in substantial compliance costs, or may require us to change our business operations.

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

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

Our operations are subject to numerous federal and state environmental laws and regulations. These laws and regulations govern, among other things, air emissions (including CO_2,methane, mercury, SO₂, and NOx), water quality, wastewater discharges, and management of hazardous, toxic, and solid wastes and substances. We incur significant costs to comply with these environmental requirements, including costs associated with the installation of pollution control equipment, environmental monitoring, emissions fees, and permits at our facilities. In addition, if we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines.

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 MATS rule, the Clean Power Plan, the CSAPR, and other air quality regulations. In addition, the EPA finalized regulations under the Clean Water Act that govern



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cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA has also adopted a final rule that would expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters; however, this rule has been stayed. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. In addition, as a result of the new Federal Executive Administration taking office in January 2017 and other factors, there is uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with existing and future environmental laws and regulations.

Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level that 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 early or converted to an alternative type of fuel. If generation facility owners in the Midwest, including us, retire a significant number of older coal-fired generation facilities, a potential reduction in the region's capacity reserve margin below acceptable risk levels may result. This could impair the reliability of the grid in the Midwest, particularly during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.

We are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation, and related legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other third parties. Due to the potential for imposition of stricter standards and greater regulation in the future, as well as the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate or could vary from the amounts currently accrued.

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

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

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

Federal, state, regional, and international authorities have undertaken efforts to limit GHG emissions. In 2015, the EPA issued the Clean Power Plan, which is a final rule that regulates GHG emissions from existing generating units, as well as a proposed federal plan as an alternative to state compliance plans. The EPA also issued final performance standards for modified and reconstructed generating units, as well as for new fossil-fueled power plants. With the January 2017 change in the Federal Executive Administration, the legal and regulatory future of federal GHG regulations, including the Clean Power Plan, faces increased uncertainty. We are continuing to analyze the GHG emission profile of our electric generation resources and to work with other stakeholders to determine the potential impacts to our operations by the implementation of the Clean Power Plan, any successor rule, and federal GHG regulations in general. In October 2015, numerous states (including Wisconsin and Michigan), trade



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associations, and private parties filed lawsuits challenging the Clean Power Plan, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the Clean Power Plan rules until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The Clean Power Plan or its successor is not expected to result in significant additional compliance costs, including capital expenditures, but may impact how we operate our existing fossil-fueled power plants and biomass facility.

There is no guarantee that we will be allowed to fully recover costs incurred to comply with the Clean Power Plan or other federal regulations, or that cost recovery will not be delayed or otherwise conditioned. The Clean Power Plan and any other related regulations that may be adopted in the future, at either the federal or state level, may cause our environmental compliance spending to differ materially from the amounts currently estimated. In December 2016, Michigan enacted Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the requirement to 15.0% for 2021. These regulations, as well as changes in the fuel markets and advances in technology, could make some of our electric generating units uneconomic to maintain or operate, and could affect unit retirement and replacement decisions. These regulations could also adversely affect our future results of operations, cash flows, and financial condition.

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

We may be negatively impacted by changes in federal income tax policy.

We are impacted by United States federal income tax policy. Both the new Federal Executive Administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes to corporate income tax laws. These proposed changes include, among other things, a reduction in the corporate income tax rate, the immediate deductibility of 100% of capital expenditures, and the elimination of the interest expense deduction. We are currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on us. However, it is possible that changes in the United States federal income tax laws could have an adverse effect on our results of operations, financial condition, and liquidity. For example, the immediate deductibility of capital expenditures could have the effect of reducing growth in our regulated rate base, which could negatively impact our results of operations.

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

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

Risks Related to the Operation of Our Business

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

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



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environmental or other regulatory requirements; terrorist attacks; or cyber security intrusions. Any of these events could lead to substantial financial losses.

Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues or cause us to incur significant costs 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, which could adversely affect our results of operations and cash flows.

Our 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, 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 negatively impacted by population declines as well as economic factors in our service territories, including job losses, decreases in income, and business closings. We are impacted by economic cycles and the competitiveness of the commercial and industrial 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 influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.

•

Weather conditions. 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 may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season may result in lower revenues and net income.

•

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

As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition.

We 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 other projects, including projects for environmental compliance.

Achieving the intended benefits of any large construction project is subject to many uncertainties, some of which we will have limited or no control over, that could adversely affect project costs and completion time. These risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy. In addition, certain of these projects require the approval of our regulators. If construction of commission-approved projects should materially and adversely deviate from the schedules, estimates, and projections on which the approval was based, our regulators may deem the additional capital costs as imprudent and disallow recovery of them through rates.



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

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

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, and energy efficiency. We generate power at central station power plants to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells, which have become more cost competitive. It is possible that 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 production. If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities could be 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.

Our operations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.

We face the risk of terrorist attacks and cyber intrusions, both threatened and actual, 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, any of which 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. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations, financial condition, and cash flows.

We operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful cyber security intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission and distribution systems, could disrupt our operations and result in loss of service to customers. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.

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

Our business requires the collection and retention of personally identifiable information of our customers and employees, who expect that we will adequately protect such information. Security breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. We may also need to obtain additional insurance coverage related to the threat of such intrusions.

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



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

Inherent in natural gas distribution activities are a variety of hazards and operational risks, such as leaks, accidental explosions, including third party damages, and mechanical problems, which could materially and adversely affect our results of operations, financial condition, and cash flows. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of natural gas pipelines and storage facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms.

We may fail to attract and retain an appropriately qualified workforce.

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

The acquisition of Integrys may not achieve its anticipated results, and WEC Energy Group may be unable to integrate operations as expected.

The Merger Agreement was entered into with the expectation that the acquisition would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, including whether the businesses of WEC Energy Group, including us, can continue to be integrated in an efficient, effective, and timely manner.

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



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Risks Related to Economic and Market Volatility

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

We rely on access to credit and capital markets to support our capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. In addition, we rely on a committed bank credit agreement as back-up liquidity, which allows us to access the low cost commercial paper markets.

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


•	A rating downgrade;


•	An economic downturn or uncertainty;


•	Prevailing market conditions and rules;


•	Concerns over foreign economic conditions;


•	Changes in tax policy;


•	War or the threat of war; and


•	The overall health and view of the utility and financial institution industries.

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

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

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

Any downgrade by the rating agencies could:


•	Increase borrowing costs under our existing credit facility;


•	Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;


•	Decrease funding sources by limiting our access to the commercial paper market;


•	Limit the availability of adequate credit support for our operations; and


•	Trigger collateral requirements in various contracts.

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

Our 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 electric generation plants, and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. The cost of natural gas may increase because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations affecting its accessibility.

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



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Changes in commodity prices could result in:


•	Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;


•	Reduced profitability to the extent that lower revenues, increased bad debt, and interest expense are not recovered through rates;


•	Higher rates charged to our customers, which could impact our competitive position;


•	Reduced demand for energy, which could impact revenues and operating expenses; and


•	Shutting down of generation facilities if the cost of 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 and engage in opportunity sales.

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

Our electric generation frequently exceeds our customer load. When this occurs, we generally sell the excess generation into the MISO Energy Markets. If we do not have an adequate supply of coal for our coal-fired units or are unable to run our lower cost units, we may lose the ability to engage in these opportunity sales, which may adversely affect our results of operations.

The use of derivative contracts could result in financial losses.

We use derivative instruments such as swaps, options, futures, and forwards to manage commodity 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 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 and revenues.

The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us.

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



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

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

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

We have significant obligations related to pension and OPEB plans. If WEC Energy Group is unable to successfully manage benefit plan assets and our medical costs, 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. 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 the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. In addition, medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, changes in interest rates, changes in demographics (including the number of retirements) or changes in life expectancy assumptions.

We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we 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; international, national, state, or local events; 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

None.



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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 ERGS and PWGS generating units from We Power.

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



Name	Location	Fuel	Number of Generating Units	Rated Capacity In MW ⁽¹⁾
Coal-fired plants
ERGS	Oak Creek, WI	Coal	2	1,057	⁽²⁾
Pleasant Prairie	Pleasant Prairie, WI	Coal	2	1,188	⁽³⁾
PIPP	Marquette, MI	Coal	5	344
OCPP	Oak Creek, WI	Coal	4	993
Total coal-fired plants			13	3,582
Natural gas-fired plants
Concord Combustion Turbines	Watertown, WI	Natural Gas/Oil	4	352
Germantown Combustion Turbines	Germantown, WI	Natural Gas/Oil	5	258
Paris Combustion Turbines	Union Grove, WI	Natural Gas/Oil	4	352
PWGS	Port Washington, WI	Natural Gas	2	1,140
VAPP	Milwaukee, WI	Natural Gas	2	240
Total natural gas-fired plants			17	2,342
Renewables
Hydro Plants (13 in number)	WI and MI	Hydro	30	89
Rothschild Biomass Plant	Rothschild, WI	Biomass	1	50
Blue Sky Green Field	Fond du Lac, WI	Wind	88	21
Byron Wind Turbines	Fond du Lac, WI	Wind	2	—
Glacier Hills	Cambria, WI	Wind	90	28
Montfort Wind Energy Center	Montfort, WI	Wind	20	2
Total renewables			231	190
Total system			261	6,114


⁽¹⁾	Based on expected capacity ratings for summer 2017, which can differ from nameplate capacity, especially on wind projects. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.


⁽²⁾	This facility is jointly owned by We Power and various other utilities. The capacity indicated for the facility is equal to We Power's portion of total plant capacity based on its 83.34% ownership.


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

As of December 31, 2016, we operated approximately 21,500 pole-miles of overhead distribution lines and 24,800 miles of underground distribution cable, as well as 355 distribution substations and approximately 301,700 line transformers.

As of December 31, 2016, our natural gas distribution system included approximately 10,200 miles of distribution mains connected at 28 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, and approximately 410,000 natural gas lateral services. We have a liquefied natural gas storage plant that converts and stores, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plant has a send-out capability of 70,000 Dth per day. Our natural gas distribution system consists almost entirely of plastic and coated steel pipe.

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



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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, 2016, the steam system supplied by the VAPP consisted of approximately 40 miles of both high pressure and low pressure steam piping, approximately four miles of walkable tunnels and other pressure regulating equipment.

General

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

ITEM 3. LEGAL PROCEEDINGS

In addition to those legal proceedings discussed in this Annual Report on Form 10-K, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these 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.

See Note 16, Commitments and Contingencies, and Note 20, Regulatory Environment, for additional information on material legal proceedings and matters related to us and our subsidiary.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.



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EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, and positions of our executive officers at December 31, 2016 are listed below along with their business experience during the past five years. All officers are appointed until they resign, die, or are removed pursuant to our 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.

Allen L. Leverett. Age 50.


•	WEC Energy Group — Chief Executive Officer since May 2016. Director since January 2016. President since August 2013. Executive Vice President from May 2004 to July 2013. Chief Financial Officer from July 2003 to February 2011.


•	WE — Chairman of the Board and Chief Executive Officer since May 2016. Director since June 2015. President from June 2015 to May 2016. Executive Vice President from May 2004 to June 2015. Chief Financial Officer from July 2003 to February 2011.

J. Kevin Fletcher. Age 58.


•	WE — President since May 2016. Director since June 2015. Executive Vice President - Customer Service and Operations from June 2015 to April 2016. Senior Vice President - Customer Operations from October 2011 to June 2015.

Robert M. Garvin. Age 50.


•	WEC Energy Group — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.


•	WE — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.

William J. Guc. Age 47.


•	WEC Energy Group — Controller since October 2015. Vice President since June 2015.


•	WE — Vice President and Controller since October 2015.


•	Integrys Energy Group — Vice President and Treasurer from December 2010 to June 2015.

Scott J. Lauber. Age 51.


•	WEC Energy Group — Executive Vice President and Chief Financial Officer since April 2016. Vice President and Treasurer from February 2013 to March 2016. Assistant Treasurer from March 2011 to January 2013.


•	WE — Director and Executive Vice President and Chief Financial Officer since April 2016. Vice President and Treasurer from February 2013 to March 2016. Assistant Treasurer from March 2011 to January 2013.

Susan H. Martin. Age 64.


•	WEC 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.


•	WE — Director since June 2015. Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.

Tom Metcalfe. Age 49.


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

James A. Schubilske. Age 51.


•	WEC Energy Group — Vice President and Treasurer since April 2016. Assistant Treasurer from June 2000 to January 2013.


•	WE — Vice President and Treasurer since April 2016. Vice President — State Regulatory Affairs from February 2013 to March 2016. Assistant Treasurer from June 2000 to January 2013.

Joan M. Shafer. Age 63.


•	WE — Executive Vice President - Human Resources and Organizational Effectiveness since June 2015. Senior Vice President - Customer Services from January 2012 to June 2015. Vice President - Customer Services from January 2004 to January 2012.

Certain executive officers also hold officer and/or director positions at other significant subsidiaries of WEC Energy Group.



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PART II

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

Dividends

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



Quarter
(in millions)	2016		2015
First	$	160.0	$	60.0
Second	60.0		60.0
Third	100.0		60.0
Fourth	135.0		60.0
Total	$	455.0	$	240.0

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

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC 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 WEC Energy Group. See Note 10, Common Equity, for more information regarding restrictions on our ability to pay dividends.



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ITEM 6. SELECTED FINANCIAL DATA

WISCONSIN ELECTRIC POWER COMPANY

COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS



As of or for Year Ended December 31
(in millions)	2016		2015		2014		2013		2012
Operating revenues	$	3,792.8	$	3,854.1	$	4,059.4	$	3,800.2	$	3,613.3
Net income attributed to common shareholder	364.3		375.7		376.7		360.0		366.1
Total assets	13,371.5		13,139.6		12,597.2		12,207.2		12,016.2
Long-term debt and capital lease obligations (excluding current portion)	5,417.6		5,351.3		4,875.2		4,876.7		4,917.5



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

CORPORATE DEVELOPMENTS

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We have combined common functions with WG and operate under the trade name of "We Energies." We conduct our business primarily through our utility reportable segment. See Note 21, Segment Information, for more information on our reportable business segments.

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

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

Corporate Strategy

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

Reliability

We have made significant reliability related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliability of our generation and distribution networks.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we received approval from the PSCW to make changes at ERGS to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.

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

Financial Discipline

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

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 3, Dispositions, for information on the sale of the MCPP.

Exceptional Customer Care

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



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

RESULTS OF OPERATIONS

Consolidated Earnings

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

Non-GAAP Financial Measures

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

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

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

Utility Segment Contribution to Operating Income



	Year Ended December 31
(in millions)	2016		2015		2014
Electric revenues	$	3,440.6	$	3,454.4	$	3,445.2
Fuel and purchased power	1,091.8		1,154.4		1,228.1
Total electric margins	2,348.8		2,300.0		2,217.1

Natural gas revenues	352.2		399.7		614.2
Cost of natural gas sold	200.3		244.6		432.6
Total natural gas margins	151.9		155.1		181.6

Total electric and natural gas margins	2,500.7		2,455.1		2,398.7

Other operation and maintenance	1,430.2		1,384.9		1,356.4
Depreciation and amortization	325.4		304.0		278.3
Property and revenue taxes	115.6		117.3		113.6
Operating income	$	629.5	$	648.9	$	650.4



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The following table shows a breakdown of other operation and maintenance:



	Year Ended December 31
(in millions)	2016		2015		2014
Operation and maintenance not included in lines items below	$	500.2	$	502.9	$	529.2
We Power ⁽¹⁾	513.2		510.7		462.1
Transmission ⁽²⁾	273.8		272.3		278.6
Regulatory amortizations and other pass through expenses ⁽³⁾	96.6		99.0		86.4
Earnings sharing mechanism	21.1		—		—
Other	25.3		—		—
Total other operation and maintenance	$	1,430.2	$	1,384.9	$	1,356.3

⁽¹⁾

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

⁽²⁾

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


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

The following tables provide information on delivered volumes by customer class and weather statistics:



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


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



	Year Ended December 31
	Therms (in millions)
Natural Gas Sales Volumes	2016	2015	2014
Customer class
Residential	341.7	341.2	399.3
Commercial and industrial	186.3	194.5	240.4
Total retail	528.0	535.7	639.7
Transport	323.8	306.9	325.5
Total sales in therms	851.8	842.6	965.2



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	Year Ended December 31
	Degree Days
Weather *	2016	2015	2014
Heating (6,679 normal)	6,068	6,468	7,616
Cooling (694 normal)	991	622	464


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

2016 Compared with 2015

Electric Utility Margins

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


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


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

Natural Gas Utility Margins

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

Operating Income

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

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


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


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


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


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

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



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2015 Compared with 2014

Electric Utility Margins

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


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


•	A $35.0 million increase driven by the escrow accounting treatment of the SSR revenues in the PSCW rate order, effective January 1, 2015. See Note 20, Regulatory Environment, for more information.

•

A $24.2 million increase due to the return of the iron ore mines as customers in February 2015. The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. Effective February 1, 2015, the owner of the two mines returned them as retail customers. In 2015, we deferred, and expect to continue to defer, the margin from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice.

•

A $10.4 million positive impact from collections of fuel and purchased power costs as compared with costs approved in rates in 2015, as compared with 2014. Under the Wisconsin fuel rules, our margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.


•	A $6.2 million increase primarily due to lower fly ash removal costs in 2015.


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


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

Natural Gas Utility Margins

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


•	A $14.9 million decrease in sales volumes in 2015, largely related to warmer weather during the heating season as well as lower weather-normalized use per customer. As measured by heating degree days, 2015 was 15.1% warmer than 2014.


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

Operating Income

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

The significant factors impacting the increase in operating expenses were:


•	A $48.6 million increase from higher lease expense related to the We Power leases and associated operating and maintenance expenses as approved in our PSCW rate order, effective January 1, 2015.



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•	A $25.7 million increase in depreciation and amortization expense, driven by:


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


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


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


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

These increases in operating expenses were partially offset by:


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


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

Equity in Earnings of Transmission Affiliate



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

2016 Compared with 2015

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

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

2015 Compared with 2014

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

Consolidated Other Income, Net



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

Consolidated Interest Expense



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



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Income Tax Expense



	Year Ended December 31
	2016		2015		2014
Effective tax rate	36.6	%	36.0	%	37.1	%

2016 Compared with 2015

Our effective tax rate was 36.6% in 2016 compared with 36.0% in 2015. This increase in our effective tax rate was primarily related to Treasury Grant activity in 2015. See Note 14, Income Taxes, for more information. We expect our 2017 annual effective tax rate to be between 36.0% and 37.0%.

2015 Compared with 2014

Our effective tax rate was 36.0% in 2015 compared with 37.1% in 2014. This decrease in our effective tax rate was primarily due to increased production activities deductions.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows for the years ended December 31:



(in millions)	2016			2015			2014			Change in 2016 Over 2015			Change in 2015 Over 2014
Cash provided by (used in):
Operating activities	$	848.4		$	674.4		$	862.8		$	174.0		$	(188.4	)
Investing activities	(436.8		)	(520.2		)	(567.5		)	83.4			47.3
Financing activities	(423.3		)	(151.1		)	(296.4		)	(272.2		)	145.3

Operating Activities

2016 Compared with 2015

Net cash provided by 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.


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

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


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


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



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

2015 Compared with 2014

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


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


•	A $76.2 million decrease in cash in 2015 related to the Treasury Grant we received in 2014 in connection with the completion of our biomass plant in November 2013.


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

Investing Activities

2016 Compared with 2015

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


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


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


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

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

2015 Compared with 2014

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

Capital Expenditures

Capital expenditures for the years ended December 31 were as follows:



	2016		2015		2014		Change in 2016 Over 2015			Change in 2015 Over 2014
Capital expenditures	$	469.5	$	519.2	$	561.8	$	(49.7	)	$	(42.6	)

2016 Compared with 2015

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

2015 Compared with 2014

The decrease in cash paid for capital expenditures during 2015 was primarily related to the conversion of the fuel source for VAPP from coal to natural gas. Most of the capital expenditures related to this project were incurred in 2014.

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



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Financing Activities

2016 Compared with 2015

Net cash used in financing activities increased $272.2 million during 2016, driven by:


•	A $250.0 million net decrease in cash due to the issuance of $500.0 million of long-term debt during 2015, partially offset by the repayment of $250.0 million of long-term debt during 2015. A portion of this issuance was also used to repay short-term debt during 2015. We did not issue or repay any long-term debt in 2016.


•	A $215.0 million increase in dividends paid on common stock during 2016. During 2016, we paid special dividends to our parent to balance our capital structure.

These increases in net cash used in 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.

2015 Compared with 2014

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


•	A $300.0 million increase in cash due to a $250.0 million increase in the issuance of long-term debt during 2015 and $50.0 million of lower repayments of long-term debt during 2015. A portion of this issuance was used to repay short-term debt during 2015.


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

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

Significant Financing Activities

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

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.

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

We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. 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. See Note 12, Short-Term Debt and Lines of Credit, for more information on our credit facility.



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At December 31, 2016, 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 13, Long-Term Debt and Capital Lease Obligations, for more information on our long-term debt.

Working Capital

Although not the case as of December 31, 2016, our current liabilities sometimes exceed our current assets. If this were to occur, we would not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for ongoing operations. We also can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.

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. However, 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 S&P Global Ratings and/or Baa3 at Moody's 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.

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 agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

Capital Requirements

Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2016:



	Payments Due by Period ⁽¹⁾
(in millions)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt obligations ⁽²⁾	$	4,988.1	$	114.9	$	723.5	$	500.1	$	3,649.6
Capital lease obligations ⁽³⁾	9,024.7		432.0		866.4		869.8		6,856.5
Operating lease obligations ⁽⁴⁾	33.5		4.4		4.7		2.7		21.7
Energy and transportation purchase obligations ⁽⁵⁾	10,216.1		685.7		1,118.2		1,038.4		7,373.8
Purchase orders ⁽⁶⁾	266.9		60.1		86.6		52.1		68.1
Pension and OPEB funding obligations ⁽⁷⁾	12.5		4.9		7.6		—		—
Total contractual obligations	$	24,541.8	$	1,302.0	$	2,807.0	$	2,463.1	$	17,969.7


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


⁽²⁾	Principal and interest payments on long-term debt (excluding capital lease obligations).


⁽³⁾	Capital lease obligations for power purchase commitments and the leases with We Power.


⁽⁴⁾	Operating lease obligations for power purchase commitments and rail car leases.


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


⁽⁶⁾	Purchase obligations related to normal business operations, information technology, and other services.


⁽⁷⁾	Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2019.



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The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note 14, Income Taxes.

AROs in the amount of $61.5 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years.

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

Capital Expenditures and Significant Capital Projects

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



(in millions)
2017	$	656.6
2018	595.3
2019	574.3
Total	$	1,826.2

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

Common Stock Matters

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

Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $1.3 billion as of December 31, 2016. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $8.0 million, $107.6 million, and $10.4 million to our pension and OPEB plans in 2016, 2015, and 2014, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 15, Employee Benefits.

Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 12, Short-Term Debt and Lines of Credit, and Note 19, Variable Interest Entities.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

Market Risks and Other Significant Risks

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



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Regulatory Recovery

We account for our regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions. Our primary regulator is the PSCW. See Note 20, Regulatory Environment, for additional information regarding recent rate proceedings and orders.

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of these deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these deferred costs is not approved by our regulators, the costs would be charged to income in the current period. In general, our regulatory assets are recovered over a period of between one to six years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2016, our regulatory assets were $2,036.6 million, and our regulatory liabilities were $864.1 million.

Commodity Costs

In the normal course of providing energy, we are subject to market fluctuations in 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 through natural gas and electric hedging programs.

Embedded within our rates are amounts to recover fuel, natural gas, and purchased power costs. We have recovery mechanisms in place that allow us to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – D. Regulation for more information on these mechanisms.

Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity 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. See Note 1(d), Revenues and Customer Receivables, for more information on our mechanism that allows for cost recovery or refund of uncollectible expense.

Weather

Our utility rates are based upon estimated normal temperatures. Our electric utility 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 utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2016, 2015 and 2014, as measured by degree days, may be found in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

Interest Rates

We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt.

Based on our variable rate debt outstanding at December 31, 2016, and December 31, 2015, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $1.6 million and $1.4 million in 2016 and 2015, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.



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Marketable Securities Return

We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by the PSCW.

The fair value of our trust fund assets and expected long-term returns were approximately:



(in millions)	As of December 31, 2016		Expected Return on Assets in 2017
Pension trust funds	$	1,102.8	7.00	%
OPEB trust funds	$	205.1	7.25	%

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

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

Economic Conditions

Our service territories are primarily within the state of Wisconsin. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.

Inflation

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 Item 1A. Risk Factors.

Industry Restructuring

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. 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 choice might be implemented, if at all, in Wisconsin.



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Restructuring in Wisconsin

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

Restructuring in Michigan

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

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. See Note 4, Related Parties, and Note 20, Regulatory Environment, for more information on UMERC.

Natural Gas Utility Industry

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

Restructuring in Wisconsin

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 provide customer classes with workably competitive market choices the 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. All of our Wisconsin customer classes have workably competitive market choices and, therefore, can purchase natural gas directly from either an alternative retail natural gas supplier or their local natural gas utility. Currently, we are unable to predict the impact of potential future industry restructuring on our results of operations or financial position.

Environmental Matters

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

Other Matters

American Transmission Company Allowed Return On Equity Complaints

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued a final order related to this complaint affirming the use of the ROEs stated in the ALJ's initial decision, effective as of the order date, on a going-forward basis. The order also requires ATC to provide refunds, with interest, for the 15-month refund period from November 13, 2013, through February 11, 2015. As of December 31, 2016, ATC had started to provide refunds to us for transmission costs paid during the refund period, and we expect the refund process to be completed by July 2017. As these refunds are received, we reduce the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense.



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In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to February 12, 2015. In June 2016, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 9.7%, as well as the 0.5% incentive adder approved for MISO transmission owners. The ALJ's initial decision is not binding on the FERC and applies to revenues collected from February 12, 2015, through May 11, 2016. We are not certain when a FERC order related to this matter will be issued.

MISO transmission owners have filed various appeals related to several of the FERC orders with the D.C. Circuit Court of Appeals as well as requests for rehearing.

Bonus Depreciation Provisions

The Protecting Americans from Tax Hikes Act of 2015 was signed into law on December 18, 2015. This act extended 50% bonus depreciation to assets placed in service during 2015 through 2017, 40% bonus depreciation to assets placed in service during 2018, and 30% bonus depreciation to assets placed in service during 2019. Bonus depreciation is an additional amount of tax deductible depreciation that is awarded above what would normally be available. Due to the resulting increase in federal tax depreciation, we did not make federal income tax payments for 2016.

Critical Accounting Policies and Estimates

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

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

Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 15, Employee Benefits, 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. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

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



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The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.



Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Projected Benefit Obligation			Impact on 2016 Pension Cost
Discount rate	(0.5)	$	68.4		$	4.8
Discount rate	0.5	(59.3		)	(3.9		)
Rate of return on plan assets	(0.5)	N/A			5.6
Rate of return on plan assets	0.5	N/A			(5.6		)

The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.



Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Postretirement Benefit Obligation			Impact on 2016 Postretirement Benefit Cost
Discount rate	(0.5)	$	21.6		$	0.6
Discount rate	0.5	(18.6		)	(0.5		)
Health care cost trend rate	(0.5)	(13.4		)	(1.2		)
Health care cost trend rate	0.5	15.2			1.4
Rate of return on plan assets	(0.5)	N/A			1.0
Rate of return on plan assets	0.5	N/A			(1.0		)

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

We establish our expected return on asset assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.00% in 2016 and 2015, and 7.25% in 2014. The actual rate of return on pension plan assets, net of fees, was 6.91%, (0.6)%, and 6.17%, in 2016, 2015, and 2014, respectively.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 15, Employee Benefits.

Regulatory Accounting

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

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off as a charge to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2016, we had $2,036.6 million in regulatory assets and $864.1 million in regulatory liabilities. See Note 7, Regulatory Assets and Liabilities, for more information.



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Unbilled Revenues

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total operating revenues during 2016 of approximately $3.8 billion included accrued revenues of $211.4 million as of December 31, 2016.

Income Tax Expense

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

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

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(k), Income Taxes, and Note 14, Income Taxes, for a discussion of accounting for income taxes.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, as well as Note 1(n), Fair Value Measurements, and

Note 1(o), Derivative Instruments, for information concerning potential market risks to which we are exposed.



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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Milwaukee, Wisconsin

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary (the “Company”) as of December 31, 2016 and 2015, and the related consolidated income statements, statements of equity, and statements of cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 28, 2017



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B. CONSOLIDATED INCOME STATEMENTS



Year Ended December 31
(in millions)	2016			2015			2014
Operating revenues	$	3,792.8		$	3,854.1		$	4,059.4

Operating expenses
Cost of sales	1,292.1			1,399.0			1,660.7
Other operation and maintenance	1,430.2			1,384.9			1,356.4
Depreciation and amortization	325.4			304.0			278.3
Property and revenue taxes	115.6			117.3			113.6
Total operating expenses	3,163.3			3,205.2			3,409.0

Operating income	629.5			648.9			650.4

Equity in earnings of transmission affiliate	55.5			47.8			57.9
Other income, net	9.1			11.2			8.7
Interest expense	117.6			119.0			116.5
Other expense	(53.0		)	(60.0		)	(49.9		)

Income before income taxes	576.5			588.9			600.5
Income tax expense	211.0			212.0			222.6
Net income	365.5			376.9			377.9

Preferred stock dividend requirements	1.2			1.2			1.2
Net income attributed to common shareholder	$	364.3		$	375.7		$	376.7

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



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C. CONSOLIDATED BALANCE SHEETS



At December 31
(in millions, except share and per share amounts)	2016		2015
Assets
Current assets
Cash and cash equivalents	$	15.4	$	27.1
Accounts receivable and unbilled revenues, net of reserves of $40.9 and $43.0, respectively	503.2		461.4
Accounts receivable from related parties	58.2		41.1
Materials, supplies, and inventories	271.0		301.6
Prepayments	138.0		171.8
Other	24.6		19.6
Current assets	1,010.4		1,022.6

Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,619.6 and $3,461.9, respectively	9,832.3		9,767.5
Regulatory assets	2,036.6		1,855.9
Equity investment in transmission affiliate	402.0		382.2
Other	90.2		111.4
Long-term assets	12,361.1		12,117.0
Total assets	$	13,371.5	$	13,139.6

Liabilities and Equity
Current liabilities
Short-term debt	$	159.0	$	144.0
Current portion of capital lease obligations	28.5		123.6
Subsidiary note payable to WEC Energy Group	18.5		19.6
Accounts payable	297.9		286.4
Accounts payable to related parties	112.9		95.7
Accrued payroll and benefits	51.8		87.5
Accrued taxes	46.0		15.6
Other	100.1		100.1
Current liabilities	814.7		872.5

Long-term liabilities
Long-term debt	2,661.1		2,658.8
Capital lease obligations	2,756.5		2,692.5
Deferred income taxes	2,333.3		2,110.0
Regulatory liabilities	853.9		741.2
Pension and OPEB obligations	167.6		210.9
Other	260.2		259.3
Long-term liabilities	9,032.6		8,672.7

Commitments and contingencies (Note 16)

Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9		332.9
Additional paid in capital	1,020.1		999.7
Retained earnings	2,140.8		2,231.4
Common shareholder's equity	3,493.8		3,564.0

Preferred stock	30.4		30.4
Total liabilities and equity	$	13,371.5	$	13,139.6

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



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D. CONSOLIDATED STATEMENTS OF CASH FLOWS



Year Ended December 31
(in millions)	2016			2015			2014
Operating activities
Net income	$	365.5		$	376.9		$	377.9
Reconciliation to cash provided by operating activities
Depreciation and amortization	325.4			323.7			302.6
Deferred income taxes and investment tax credits, net	206.2			178.9			191.4
Contributions and payments related to pension and OPEB plans	(8.0		)	(107.6		)	(10.4		)
Equity income in transmission affiliate, net of distributions	(17.2		)	(4.9		)	(7.4		)
Payments for liabilities transferred to WBS	(116.0		)	—			—
Change in –
Accounts receivable and unbilled revenues	(59.0		)	(2.9		)	91.0
Materials, supplies, and inventories	30.6			18.8			(39.5		)
Prepaid taxes	39.4			(2.8		)	(2.5		)
Other current assets	9.3			0.3			(6.2		)
Accounts payable	31.3			(5.9		)	18.2
Accrued taxes	30.4			(42.1		)	(7.5		)
Other current liabilities	10.7			(1.2		)	(36.8		)
Other, net	(0.2		)	(56.8		)	(8.0		)
Net cash provided by operating activities	848.4			674.4			862.8

Investing activities
Capital expenditures	(469.5		)	(519.2		)	(561.8		)
Capital contributions to transmission affiliate	(16.1		)	(4.6		)	(11.5		)
Proceeds from the sale of assets	31.7			0.2			6.0
Proceeds from assets transferred to WBS	13.1			—			—
Other, net	4.0			3.4			(0.2		)
Net cash used in investing activities	(436.8		)	(520.2		)	(567.5		)

Financing activities
Dividends paid on common stock	(455.0		)	(240.0		)	(390.0		)
Dividends paid on preferred stock	(1.2		)	(1.2		)	(1.2		)
Issuance of long-term debt	—			500.0			250.0
Retirement of long-term debt	—			(250.0		)	(300.0		)
Change in short-term debt	15.0			(162.8		)	131.9
Repayment of subsidiary note to WEC Energy Group	(1.1		)	(2.9		)	—
Other, net	19.0			5.8			12.9
Net cash used in financing activities	(423.3		)	(151.1		)	(296.4		)

Net change in cash and cash equivalents	(11.7		)	3.1			(1.1		)
Cash and cash equivalents at beginning of year	27.1			24.0			25.1
Cash and cash equivalents at end of year	$	15.4		$	27.1		$	24.0

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



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E. CONSOLIDATED STATEMENTS OF EQUITY



	Wisconsin Electric Power Company Common Shareholder's Equity
	Common Stock		Additional Paid-In Capital		Retained Earnings			Total Common Shareholder's Equity			Preferred Stock		Total Equity
(in millions)	Common Stock		Additional Paid-In Capital		Retained Earnings			Total Common Shareholder's Equity			Preferred Stock		Total Equity
Balance at December 31, 2013	$	332.9	$	965.1	$	2,108.8		$	3,406.8		$	30.4	$	3,437.2
Net income	—		—		377.9			377.9			—		377.9
Dividends
Common stock	—		—		(390.0		)	(390.0		)	—		(390.0		)
Preferred stock	—		—		(1.2		)	(1.2		)	—		(1.2		)
Stock-based compensation	—		3.5		—			3.5			—		3.5
Tax benefit of exercised stock options allocated from parent	—		15.8		—			15.8			—		15.8
Balance at December 31, 2014	$	332.9	$	984.4	$	2,095.5		$	3,412.8		$	30.4	$	3,443.2
Net income	—		—		376.9			376.9			—		376.9
Dividends
Common stock	—		—		(240.0		)	(240.0		)	—		(240.0		)
Preferred stock	—		—		(1.2		)	(1.2		)	—		(1.2		)
Stock-based compensation	—		3.2		—			3.2			—		3.2
Tax benefit of exercised stock options allocated from parent	—		12.1		—			12.1			—		12.1
Other	—		—		0.2			0.2			—		0.2
Balance at December 31, 2015	$	332.9	$	999.7	$	2,231.4		$	3,564.0		$	30.4	$	3,594.4
Net income	—		—		365.5			365.5			—		365.5
Dividends
Common stock	—		—		(455.0		)	(455.0		)	—		(455.0		)
Preferred stock	—		—		(1.2		)	(1.2		)	—		(1.2		)
Stock-based compensation	—		1.1		—			1.1			—		1.1
Tax benefit of exercised stock options allocated from parent	—		19.3		—			19.3			—		19.3
Other	—		—		0.1			0.1			—		0.1
Balance at December 31, 2016	$	332.9	$	1,020.1	$	2,140.8		$	3,493.8		$	30.4	$	3,524.2

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



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F. CONSOLIDATED STATEMENTS OF CAPITALIZATION



At December 31 (in millions)			2016			2015
Common shareholder's equity (see accompanying statement)			3,493.8			3,564.0
Preferred stock			30.4			30.4
Long-term debt	Interest Rate	Year Due
Debentures (unsecured)	1.70%	2018	250.0			250.0
	4.25%	2019	250.0			250.0
	2.95%	2021	300.0			300.0
	3.10%	2025	250.0			250.0
	6.50%	2028	150.0			150.0
	5.625%	2033	335.0			335.0
	5.70%	2036	300.0			300.0
	3.65%	2042	250.0			250.0
	4.25%	2044	250.0			250.0
	4.30%	2045	250.0			250.0
	6.875%	2095	100.0			100.0

Note (secured, nonrecourse)	4.81%	2030	2.0			2.0

Obligations under capital leases			2,785.0			2,816.1
Total			5,472.0			5,503.1
Unamortized debt issuance costs			(3.6		)	(3.9		)
Unamortized discount, net			(22.3		)	(24.3		)
Total long-term debt and capital lease obligations, including current portion			5,446.1			5,474.9
Current portion of capital lease obligations			(28.5		)	(123.6		)
Total long-term debt and capital lease obligations			5,417.6			5,351.3
Total long-term capitalization			$	8,941.8		$	8,945.7

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



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G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) General Information—On June 29, 2015, our parent company, Wisconsin Energy Corporation, acquired Integrys and changed its name to WEC Energy Group, Inc. See Note 2, Acquisitions, for more information on this acquisition.

We are an electric, natural gas, and steam utility company that serves electric customers in Wisconsin and an iron ore mine owned by the Tilden Mining Company (Tilden) in the Upper Peninsula of Michigan, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin.

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and it became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets previously held by us and WPS located in the Upper Peninsula of Michigan. The existing contract between us and the Tilden Mining Company will remain in place until a new power generation solution for the region is commercially operational.

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted.

At December 31, 2016, we had one wholly owned subsidiary, Bostco. Bostco had total assets of $24.4 million and $29.8 million as of December 31, 2016 and 2015, respectively. The financial statements include our accounts and the accounts of our wholly owned subsidiary. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

During the second quarter of 2016, we reorganized our business segments to reflect our new internal organization and management structure. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 21, Segment Information, for more information on our business segments.

We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(b) Balance Sheet Presentation— To be consistent with the current year presentation, we changed our December 31, 2015 balance sheet from a utility format to a traditional format. This change revised the order of certain balance sheet line items, but it did not result in any change to the classification of amounts between line items.

(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.

(d) Revenues and Customer Receivables—We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers.

We present revenues net of pass-through taxes on the income statements.

Below is a summary of the significant mechanisms we had in place that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts:


•	Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations.

•

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW.



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•	We received payments from MISO under an SSR agreement for our PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 20, Regulatory Environment, for more information.


•	Our natural gas utility rates included a one-for-one recovery mechanism for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.


•	Our residential rates included a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

Revenues are also impacted by other accounting policies related to our participation in the MISO Energy Markets. We sell and purchase power in the MISO Energy Markets, which operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour. If we were a net seller in a particular hour, the net amount was reported as operating revenues. If we were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements.

We provide regulated electric, natural gas, and steam service to customers in Wisconsin and provided electric service to customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 4, Related Parties, and Note 20, Regulatory Environment, for information regarding the transfer of our customers located in the Upper Peninsula of Michigan to UMERC as of January 1, 2017. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2016. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2016.

(e) Materials, Supplies, and Inventories—Our inventory as of December 31 consisted of:



(in millions)	2016		2015
Materials and supplies	$	148.1	$	151.1
Fossil fuel	91.1		110.5
Natural gas in storage	31.8		40.0
Total	$	271.0	$	301.6

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

(f) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 7, Regulatory Assets and Liabilities, for more information.

(g) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation over the estimated useful life of utility property using depreciation rates approved by the PSCW and MPSC that include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.00%, 3.01%, and 2.93% in 2016, 2015, and 2014, respectively.



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We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

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

(h) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on stockholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net.

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.45% for 2016 and 2015, and 9.09% for 2014. Our average AFUDC wholesale rates were 2.73%, 1.72%, and 0.87% for 2016, 2015, and 2014, respectively.

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



(in millions)	2016		2015		2014
AFUDC – Debt	$	1.7	$	2.2	$	1.8
AFUDC – Equity	$	4.2	$	5.7	$	4.4

(i) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted to their present values each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.

(j) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 16, Commitments and Contingencies, for more information regarding manufactured gas plant sites.

We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state's Commission's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(k) Income Taxes—We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to



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assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 14, Income Taxes, for more information.

We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements.

(l) Employee Benefits—The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 15, Employee Benefits, for more information.

(m) Stock-Based Compensation—Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides a long-term incentive through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million.

Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period based on an estimate of the final expected value of the awards.

Stock Options

Our employees are granted WEC Energy Group non-qualified stock options that vest on a cliff-basis after a three-year period. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant.

WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models:



	2016			2015			2014
Non-qualified stock options granted *	92,880			495,550			864,860

Estimated fair value per non-qualified stock option	$	4.92		$	5.29		$	4.18

Risk-free interest rate	0.5% – 2.2%			0.1% – 2.1%			0.1% – 3.0%
Dividend yield	4.0		%	3.7		%	3.8		%
Expected volatility	18.0		%	18.0		%	18.0		%
Expected life (years)	5.8			5.8			5.8


*	Effective January 1, 2016, certain of our employees were transferred into WBS. See Note 4, Related Parties, for more information.

The risk-free interest rate is based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's current dividend rate and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience.



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Restricted Shares

WEC Energy Group restricted shares have a three-year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. The restricted shares are classified as equity awards.

Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three-year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. All grants are settled in cash and are accounted for as liability awards accordingly. Stock-based compensation costs are recorded over the three-year performance period.

See Note 10, Common Equity, for more information on WEC Energy Group's stock-based compensation plans.

(n) Fair Value Measurements—Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs.

We recognize transfers at their value as of the end of the reporting period.

Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

See Note 17, Fair Value Measurements, for more information.



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(o) Derivative Instruments—We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW.

We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on our income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 18, Derivative Instruments, for more information.

(p) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

NOTE 2—ACQUISITIONS

Parent Company's Acquisition of Integrys

On June 29, 2015, our parent company acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc. Integrys is a provider of regulated natural gas and electricity, as well as nonregulated renewable energy.

The acquisition was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order includes the following conditions:

•

We are subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanism, if we earn over our authorized rate of return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and will reduce our transmission escrow. All utility earnings above the first 50 basis points will be solely used to reduce the transmission escrow. For the year ended December 31, 2016, we recorded $21.1 million of expense related to this earnings sharing mechanism.


•	Any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and WPS filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that no new generation is currently needed.

We do not believe that the conditions set forth in the various regulatory orders approving the acquisition will have a material impact on our operations or financial results.

In 2015, we recorded $6.6 million of severance expense that resulted from employee reductions related to the post-acquisition integration. Severance expense incurred during 2016 was not significant. The severance expense was recorded in our utility segment and is included in the other operation and maintenance line item on the income statements. Severance payments of $4.6 million and



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$1.2 million were made during 2016 and 2015, respectively. The severance accruals on our balance sheets were not significant at December 31, 2016 and 2015.

Parent Company's Acquisition of a Natural Gas Storage Facility in Michigan

In January 2017, our parent company signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide for some of our storage needs for our natural gas utility operations. We plan to enter into a long-term service agreement to take the allocated storage, subject to PSCW approval and closing of the acquisition. PSCW approval and closing of this transaction are expected to occur by the third quarter of 2017.

NOTE 3—DISPOSITIONS

Utility Segment – Sale of Milwaukee County Power Plant

In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ($6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

NOTE 4—RELATED PARTIES

We and our consolidated subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, ATC, and other affiliated entities.

We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the acquisition of Integrys by Wisconsin Energy Corporation on June 29, 2015, an AIA (Non-WBS AIA) went into effect. The Non-WBS AIA governed the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS continued to provide services to Integrys and its subsidiaries only under the existing WBS AIAs. WBS provided services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us, under interim WBS AIAs. The PSCW and all other relevant state commissions approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA.

Services under the Non-WBS AIA were subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary were priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary were priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary were priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS were priced at cost.

WBS provided several categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBS AIAs, which were approved, or from which we were granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the interim WBS AIAs. Other modifications or amendments to the interim WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases.

On April 1, 2016, we, along with WEC Energy Group, filed a new agreement for approval with the PSCW and all other relevant state commissions. The PSCW approved the new agreement in August 2016. We later received approval from the two other states reviewing the agreement, and the new agreement took effect January 1, 2017. The new agreement replaces the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements being replaced. In February 2017, a request was filed with the PSCW for modifications to the new AIA to incorporate WEC Energy Group's acquisition of a natural gas storage facility in Michigan. See Note 2, Acquisitions, for more information on the natural gas storage facility acquisition.



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Effective January 1, 2016, 485 of our employees were transferred into WBS. In connection with this transfer of employees, certain benefit-related liabilities were also transferred to WBS. In addition, we transferred certain software assets to WBS in 2016.

We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost. On January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information.

Bostco has a note payable to our parent company, WEC Energy Group. At December 31, 2016 and 2015, the balance of this note payable was $18.5 million and $19.6 million, respectively.

The following table shows activity associated with our related party transactions for the years ended December 31:



(in millions)	2016		2015		2014
Lease agreements
Lease payments to We Power ⁽¹⁾	$	412.2	$	410.5	$	389.0
CWIP billed to We Power	37.9		58.8		41.0

Transactions with WBS ⁽²⁾
Billings to WBS ⁽³⁾	213.8		11.1		—
Billings from WBS ⁽⁴⁾	310.6		1.3		—

Transactions with WPS ⁽²⁾
Billings to WPS	9.0		13.4		—
Billings from WPS	4.2		4.9		—

Transactions with WG
Natural gas purchases from WG	5.3		5.3		6.6
Services received from WG	21.5		23.5		20.6
Services provided to WG	60.6		79.4		81.7


⁽¹⁾	We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS 1, PWGS 2, ER 1, and ER 2.


⁽²⁾	Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs discussed above.


⁽³⁾	Includes $13.1 million for the transfer of certain software assets to WBS for the year ended December 31, 2016.


⁽⁴⁾	Includes $116.0 million for the transfer of certain benefit-related liabilities to WBS for the year ended December 31, 2016.

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The estimated net book value of the property, plant, and equipment transferred to UMERC from us as of January 1, 2017, was $83 million. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in a gain or loss recognized.

UMERC obtains its energy through the MISO Energy Markets and meets its market obligations through power purchase agreements with us and WPS. The new utility has also proposed a long-term generation solution for electric reliability in the region. See Note 20, Regulatory Environment, for more information. The Tilden Mining Company will remain a customer of ours until this new generation begins commercial operation.



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NOTE 5—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

At December 31, 2016, we owned approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. On January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in a gain or loss recognized. WEC Energy Group has one representative on ATC's ten-member board of directors. Each member of the board has only one vote. Due to voting requirements, no individual board member has more than 10% of the voting control. The following table shows changes to our investment in ATC during the years ended December 31:



(in millions)	2016			2015		2014
Balance at beginning of period	$	382.2		$	372.9	$	354.1
Add: Earnings from equity method investment	55.5			47.8		57.9
Add: Capital contributions	16.1			4.6		11.5
Less: Distributions	51.7		*	42.9		50.5
Less: Other	0.1			0.2		0.1
Balance at end of period	$	402.0		$	382.2	$	372.9


*	Of this amount, $13.4 million was recorded as a receivable at December 31, 2016.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.

The following table summarizes our significant related party transactions with ATC during the years ended December 31:



(in millions)	2016		2015		2014
Charges to ATC for services and construction	$	10.0	$	9.7	$	8.1
Charges from ATC for network transmission services	247.8		238.5		231.4

As of December 31, 2016 and 2015, our balance sheets included the following receivables and payables related to ATC:



(in millions)	2016		2015
Accounts receivable
Services provided to ATC	$	1.1	$	0.6
Accounts payable
Services received from ATC	20.0		19.9

Summarized financial data for ATC is included in the tables below:



(in millions)	2016		2015		2014
Income statement data
Revenues	$	650.8	$	615.8	$	635.0
Operating expenses	322.5		319.3		307.4
Other expense	95.5		96.1		88.9
Net income	$	232.8	$	200.4	$	238.7



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(in millions)	December 31, 2016		December 31, 2015
Balance sheet data
Current assets	$	75.8	$	80.5
Noncurrent assets	4,312.9		3,948.3
Total assets	$	4,388.7	$	4,028.8

Current liabilities	$	495.1	$	330.3
Long-term debt	1,865.3		1,790.7
Other noncurrent liabilities	271.5		245.0
Shareholders' equity	1,756.8		1,662.8
Total liabilities and shareholders' equity	$	4,388.7	$	4,028.8

NOTE 6—SUPPLEMENTAL CASH FLOW INFORMATION



(in millions)	2016			2015			2014
Cash (paid) for interest, net of amount capitalized	$	(116.2	)	$	(116.2	)	$	(117.9	)
Cash received (paid) for income taxes, net	100.2			(58.5		)	(20.8		)
Significant non-cash transactions:
Accounts payable related to construction costs	9.1			11.7			1.7

NOTE 7—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets as of December 31:



(in millions)	2016		2015		See Note
Regulatory assets ^{(1) (2)}
Plant related – capital leases	$	724.8	$	674.4	13
Unrecognized pension and OPEB costs ⁽³⁾	520.3		535.8		15
Electric transmission costs	231.9		191.5		20
Income tax related items ⁽⁴⁾	200.8		177.4
SSR	188.1		86.1		20
We Power generation⁽⁵⁾	54.1		45.4
AROs	39.7		36.3		9
Energy efficiency programs ⁽⁶⁾	38.5		50.7
Other, net	38.4		58.3
Total regulatory assets	$	2,036.6	$	1,855.9


⁽¹⁾	Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in the table.


⁽²⁾	As of December 31, 2016, we had $10.4 million of regulatory assets not earning a return and $204.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures.


⁽³⁾	Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan.


⁽⁴⁾	Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse.


⁽⁵⁾	Represents amounts recoverable from customers related to our costs of the generating units leased from We Power, including subsequent capital additions.


⁽⁶⁾	Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards.



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The following regulatory liabilities were reflected on our balance sheets as of December 31:



(in millions)	2016		2015
Regulatory liabilities
Removal costs⁽¹⁾	$	722.9	$	696.9
Mines deferral ⁽²⁾	70.2		31.6
Other, net	71.0		12.7
Total regulatory liabilities	$	864.1	$	741.2

Balance Sheet Presentation
Other current liabilities	$	10.2	$	—
Regulatory liabilities	853.9		741.2
Total regulatory liabilities	$	864.1	$	741.2


⁽¹⁾	Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.


⁽²⁾	Represents the deferral of revenues less the associated cost of sales related to the mines, which were not included in the 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding.

NOTE 8—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31:



(in millions)	2016		2015
Utility property, plant, and equipment	$	11,232.9	$	10,863.1
Less: Accumulated depreciation	3,606.9		3,447.2
Net	7,626.0		7,415.9
CWIP	111.5		170.3
Net utility property, plant, and equipment	7,737.5		7,586.2

Property under capital leases	2,898.0		2,876.7
Less: Accumulated amortization	837.8		735.0
Net leased facilities	2,060.2		2,141.7

Non-utility and other property, plant, and equipment	46.4		54.0
Less: Accumulated depreciation	12.7		14.7
Net	33.7		39.3
CWIP	0.9		0.3
Net non-utility and other property, plant, and equipment	34.6		39.6

Total property, plant, and equipment	$	9,832.3	$	9,767.5

On January 1, 2017, we transferred 2,500 miles of electric distribution lines and related electric distribution substations in the Upper Peninsula of Michigan to UMERC. The estimated net book value of the property, plant, and equipment we transferred to UMERC was $83 million. See Note 4, Related Parties, for more information.

NOTE 9—ASSET RETIREMENT OBLIGATIONS

We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities, the removal and dismantlement of generation facilities, and the closure of fly-ash landfills at our generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. On our balance sheets, AROs are recorded within other long-term liabilities.



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The following table shows changes to our AROs during the years ended December 31:



(in millions)	2016			2015			2014
Balance as of January 1	$	58.7		$	40.5		$	39.4
Accretion	3.0			2.3			2.2
Additions	—			15.9		*	—
Liabilities settled	(0.2		)	—			(1.1		)
Balance as of December 31	$	61.5		$	58.7		$	40.5


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

NOTE 10—COMMON EQUITY

Stock-Based Compensation Plans

The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit for the years ended December 31:



(in millions)	2016		2015		2014
Stock options	$	1.8	$	3.2	$	3.6
Restricted stock	1.8		2.1		2.1
Performance units	3.9		7.5		12.7
Stock-based compensation expense	$	7.5	$	12.8	$	18.4
Related tax benefit	$	3.0	$	5.1	$	7.4

Stock-based compensation costs capitalized during 2016, 2015, and 2014 were not significant.

Stock Options

The following is a summary of our employees' WEC Energy Group stock option activity during 2016:



Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2016	5,687,714		$	33.58
Granted	92,880		$	50.93
Exercised	(439,043	)	$	27.57
Transferred *	(4,055,745	)	$	34.68
Outstanding as of December 31, 2016	1,285,806		$	33.41	4.6	$	32.4
Exercisable as of December 31, 2016	1,010,061		$	29.64	3.7	$	29.3


*	Relates to the transfer of certain employees into WBS. See Note 4, Related Parties, for more information.

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2016. This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2016, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2016, 2015, and 2014 was $14.1 million, $34.6 million, and $47.5 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $12.1 million, $29.2 million, and $47.9 million during the years ended December 31, 2016, 2015, and 2014, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $5.6 million, $14.0 million, and $18.8 million, respectively.

As of December 31, 2016, our estimated unrecognized compensation cost related to unvested WEC Energy Group stock options was not significant.



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During the first quarter of 2017, the Compensation Committee awarded 80,770 non-qualified WEC Energy Group stock options with an exercise price of $58.31 and a weighted-average grant date fair value of $7.12 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following is a summary of our employees' WEC Energy Group restricted stock activity during 2016:



Restricted Shares	Number of Shares		Weighted-Average Grant Date Fair Value
Outstanding as of January 1, 2016	175,443		$	47.66
Granted	8,049		$	51.78
Released	(7,901	)	$	44.66
Transferred *	(158,635	)	$	47.73
Forfeited	(695	)	$	50.42
Outstanding as of December 31, 2016	16,261		$	50.39


*	Relates to the transfer of certain employees into WBS. See Note 4, Related Parties, for more information.

The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.4 million, $2.7 million, and

$2.3 million for the years ended December 31, 2016, 2015, and 2014, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.2 million, $1.1 million, and $0.9 million, respectively.

As of December 31, 2016, our estimated unrecognized compensation cost related to WEC Energy Group restricted stock was not significant.

During the first quarter of 2017, the Compensation Committee awarded 8,001 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $58.10 per share.

Performance Units

In 2016, 2015, and 2014, the Compensation Committee awarded 35,700; 187,450; and 224,735 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan.

In 2016, we transferred 573,499 performance units to WBS in connection with the transfer of certain employees. See Note 4, Related Parties, for more information.

Performance units with an intrinsic value of $3.4 million, $11.6 million, and $13.1 million were settled during 2016, 2015, and 2014, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units for the same years was approximately $0.5 million, $4.2 million, and $4.7 million, respectively.

As of December 31, 2016, we expect to recognize approximately $4.4 million of unrecognized compensation cost related to WEC Energy Group performance units over the next 1.4 years on a weighted-average basis.

During the first quarter of 2017, performance units held by our employees with an intrinsic value of $1.4 million were settled. The actual tax benefit realized from the distribution of these awards was $0.4 million. In January 2017, the Compensation Committee also awarded 34,765 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restrictions

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



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In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 51%. A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level.

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

See Note 12, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2016, our restricted retained earnings totaled $1.9 billion. Our equity in undistributed earnings of investees accounted for by the equity method was $142.2 million at December 31, 2016.

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

NOTE 11—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2016 and 2015:



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

NOTE 12—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:



(in millions, except percentages)	2016			2015
Commercial paper
Amount outstanding at December 31	$	159.0		$	144.0
Average interest rate on amounts outstanding at December 31	0.87		%	0.70		%

Our average amount of commercial paper borrowings based on daily outstanding balances during 2016 was $110.0 million, with a weighted-average interest rate during the period of 0.54%.

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

As of December 31, 2016, we had approximately $323.0 million of available capacity under our bank back-up credit facility and $159.0 million of commercial paper outstanding that was supported by the credit facility. As of December 31, 2016, our subsidiary had an $18.5 million note payable to WEC Energy Group with a weighted-average interest rate of 5.17%.



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The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31:



(in millions)	Maturity	2016
Revolving credit facility	December 2020	$	500.0

Less:
Letters of credit issued inside credit facility		$	18.0
Commercial paper outstanding		159.0

Available capacity under existing agreement		$	323.0

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

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

NOTE 13—LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

See our statements of capitalization for details on our long-term debt.

Debentures and Notes

The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2016:



(in millions)
2017	$	—
2018	250.0
2019	250.0
2020	—
2021	300.0
Thereafter	1,887.0
Total	$	2,687.0

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

We are the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of

$80.0 million. In August 2009, we terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2016, the repurchased bonds were still outstanding, but are not reported in our long-term debt or included in our capitalization statements since they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on this bond series and have it remarketed to third parties. A related bond series that had an outstanding principal amount of $67.0 million matured on August 1, 2016.

Obligations Under Capital Leases

We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under capital lease accounting, we have recorded the leased plants and corresponding obligations under the capital leases on our balance sheets. We treat these agreements as operating leases for rate-making purposes. We record our minimum lease payments under the power purchase contract as purchased power expense on our income statements. We record the lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease



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accounting as a deferred regulatory asset on our balance sheets. See Note 7, Regulatory Assets and Liabilities, for more information on our plant related capital leases.

Power Purchase Commitment

In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as cost of sales on our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately

$78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $29.6 million as of December 31, 2016, and will decrease to zero over the remaining life of the contract.

Port Washington Generating Station

We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. The leased units and corresponding obligations for the units have been recorded at the estimated fair value of $704.2 million. We are amortizing the leased units on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $130.8 million in the year 2021 for PWGS 1 and to approximately $131.6 million in the year 2024 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for the units was $636.1 million as of December 31, 2016, and will decrease to zero over the remaining lives of the contracts.

Elm Road Generating Station

We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30-year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The leased units and corresponding capital lease obligations have been recorded at the estimated fair value of $2,053.5 million. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $542.8 million in the year 2029 for ER 1 and to approximately $447.2 million in the year 2030 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases was $2,119.3 million as of December 31, 2016, and will decrease to zero over the remaining lives of the contracts.

We paid the following lease payments during 2016, 2015, and 2014:



(in millions)	2016		2015		2014
Long-term power purchase commitment	$	37.6	$	36.2	$	34.9
PWGS	82.4		103.8		99.2
ERGS	329.8		306.7		277.8
Total	$	449.8	$	446.7	$	411.9



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



(in millions)	2016			2015
Long-term power purchase commitment
Under capital lease	$	140.3		$	140.3
Accumulated amortization	(109.5		)	(103.9		)
Total long-term power purchase commitment	$	30.8		$	36.4

PWGS
Under capital lease	$	704.2		$	692.5
Accumulated amortization	(274.7		)	(245.7		)
Total PWGS	$	429.5		$	446.8

ERGS
Under capital lease	$	2,053.5		$	2,043.9
Accumulated amortization	(453.6		)	(385.4		)
Total ERGS	$	1,599.9		$	1,658.5

Total leased facilities	$	2,060.2		$	2,141.7

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2016 are as follows:



(in millions)	Power Purchase Commitment			PWGS			ERGS			Total
2017	$	13.9		$	102.7		$	315.4		$	432.0
2018	14.7			102.7			315.4			432.8
2019	15.5			102.7			315.4			433.6
2020	16.4			102.7			315.4			434.5
2021	17.2			102.7			315.4			435.3
Thereafter	7.6			1,020.2			5,828.7			6,856.5
Total minimum lease payments	85.3			1,533.7			7,405.7			9,024.7
Less: Estimated executory costs	(39.9		)	—			—			(39.9		)
Net minimum lease payments	45.4			1,533.7			7,405.7			8,984.8
Less: Interest	(15.8		)	(897.6		)	(5,286.4		)	(6,199.8		)
Present value of minimum lease payments	29.6			636.1			2,119.3			2,785.0
Less: Due currently	(2.7		)	(13.9		)	(11.9		)	(28.5		)
Long-term obligations under capital lease	$	26.9		$	622.2		$	2,107.4		$	2,756.5

NOTE 14—INCOME TAXES

Income Tax Expense

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



(in millions)	2016			2015			2014
Current tax expense	$	4.8		$	33.1		$	31.2
Deferred income taxes, net	207.3			180.0			192.5
Investment tax credit, net	(1.1		)	(1.1		)	(1.1		)
Total income tax expense	$	211.0		$	212.0		$	222.6



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Statutory Rate Reconciliation

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



	2016					2015					2014
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
Expected tax at statutory federal tax rates	$	201.4		35.0	%	$	205.7		35.0	%	$	209.8		35.0	%
State income taxes net of federal tax benefit	31.8			5.5	%	31.0			5.3	%	33.0			5.5	%
Production tax credits	(16.5		)	(2.8	)%	(17.8		)	(3.0	)%	(17.4		)	(2.9	)%
Domestic production activities deduction	(7.8		)	(1.4	)%	(7.8		)	(1.3	)%	—			—	%
AFUDC – Equity	(1.5		)	(0.3	)%	(2.0		)	(0.3	)%	(1.5		)	(0.2	)%
Investment tax credit restored	(1.1		)	(0.2	)%	(1.1		)	(0.2	)%	(1.1		)	(0.2	)%
Other, net	4.7			0.8	%	4.0			0.5	%	(0.2		)	(0.1	)%
Total income tax expense	$	211.0		36.6	%	$	212.0		36.0	%	$	222.6		37.1	%

Deferred Income Tax Assets and Liabilities

The components of deferred income taxes as of December 31 were as follows:



(in millions)	2016		2015
Deferred tax assets
Deferred revenues	$	207.2	$	219.9
Future federal tax benefits	143.7		72.9
Employee benefits and compensation	77.6		103.2
Construction advances	20.0		17.7
Uncollectible account expense	16.1		14.3
Emission allowances	0.2		0.2
Other	70.9		48.7
Total deferred tax assets	535.7		476.9

Deferred tax liabilities
Property-related	2,257.3		2,058.5
Investment in transmission affiliate	195.1		174.9
Employee benefits and compensation	179.3		164.6
Deferred transmission costs	93.1		76.7
Prepaid tax, insurance, and other	50.2		50.6
Other	94.0		61.6
Total deferred tax liabilities	2,869.0		2,586.9
Deferred tax liability, net	$	2,333.3	$	2,110.0

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

As of December 31, 2016, we had $82.8 million and $107.2 million of federal net operating loss and tax credit carryforwards resulting in deferred tax assets of $29.0 million and $107.2 million, respectively. These federal net operating loss and tax credit carryforwards begin to expire in 2031. We expect to have future taxable income sufficient to utilize these deferred tax assets. As of December 31, 2015, we had approximately $72.9 million of deferred tax assets associated with tax credit carryforwards. As of December 31, 2016 we had $149.9 million state net operating loss carryforwards resulting in deferred tax assets of $7.5 million. These state net operating loss carryforwards begin to expire in 2025. We expect to have future taxable income sufficient to utilize these deferred tax assets.



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Unrecognized Tax Benefits

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



(in millions)	2016			2015
Balance as of January 1	$	6.1		$	7.2
Reductions for tax positions of prior years	(1.0		)	(1.1		)
Balance as of December 31	$	5.1		$	6.1

The amount of unrecognized tax benefits as of December 31, 2016 and 2015 excludes deferred tax assets related to uncertainty in income taxes of $5.1 million and $6.1 million, respectively. As of December 31, 2016 and 2015, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2016, 2015, and 2014, we recognized $0.2 million of interest expense, $0.1 million of interest income, and $0.3 million of interest expense, respectively, in our income statements. For the years ended December 31, 2016, 2015, and 2014, we recognized no penalties in our income statements. As of December 31, 2016 and 2015, we had $0.7 million and $0.6 million, respectively, of interest accrued on our balance sheets.

Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2013 through 2016 are subject to federal examination and the tax years 2012 through 2016 are subject to examination by the state of Wisconsin.

NOTE 15—EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We participate in WEC Energy Group's defined benefit pension plans and OPEB plans that cover substantially all of our employees. We are responsible for our share of the plan assets and obligations. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

Generally, employees who started with us after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. New management employees hired after December 31, 2014 receive a 6% annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.

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



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The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:



	Pension Costs						OPEB Costs
(in millions)	2016			2015			2016			2015
Change in benefit obligation
Obligation at January 1	$	1,290.6		$	1,315.2		$	313.8		$	322.3
Service cost	10.5			14.7			7.3			9.0
Interest cost	49.7			52.9			13.2			13.4
Participant contributions	—			—			8.8			8.8
Plan amendments	(2.6		)	—			—			—
Transfer to affiliates *	(121.1		)	(2.4		)	(17.0		)	—
Actuarial loss (gain)	25.3			(11.5		)	(9.7		)	(22.3		)
Benefit payments	(75.4		)	(78.3		)	(19.0		)	(18.7		)
Federal subsidy on benefits paid	N/A			N/A			1.1			1.3
Obligation at December 31	$	1,177.0		$	1,290.6		$	298.5		$	313.8

Change in fair value of plan assets
Fair value at January 1	$	1,179.3		$	1,160.0		$	216.1		$	224.9
Actual return on plan assets	73.0			(7.8		)	13.5			(1.5		)
Employer contributions	5.3			105.0			2.7			2.6
Participant contributions	—			—			8.8			8.8
Transfer to/from affiliates *	(79.4		)	0.4			(17.0		)	—
Benefit payments	(75.4		)	(78.3		)	(19.0		)	(18.7		)
Fair value at December 31	$	1,102.8		$	1,179.3		$	205.1		$	216.1
Funded status at December 31	$	(74.2	)	$	(111.3	)	$	(93.4	)	$	(97.7	)


*	Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. See Note 4, Related Parties, for more information.

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:



	Pension Costs						OPEB Costs
(in millions)	2016			2015			2016			2015
Other long-term assets	$	—		$	—		$	—		$	1.9
Pension and OPEB obligations	74.2			111.3			93.4			99.6
Total net liabilities	$	(74.2	)	$	(111.3	)	$	(93.4	)	$	(97.7	)

The accumulated benefit obligation for all defined benefit pension plans was $1,175.8 million and $1,287.5 million as of December 31, 2016 and 2015, respectively.

The following table shows information for the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:



(in millions)	2016		2015
Projected benefit obligation	$	1,177.0	$	1,290.2
Accumulated benefit obligation	1,175.8		1,289.5
Fair value of plan assets	1,102.8		1,178.9

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31:



	Pension Costs				OPEB Costs
(in millions)	2016		2015		2016			2015
Net regulatory assets
Net actuarial loss	$	518.5	$	520.9	$	4.6		$	14.7
Prior service cost (credit)	0.2		4.3		(3.0		)	(4.1		)
Total	$	518.7	$	525.2	$	1.6		$	10.6



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The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2017:



(in millions)	Pension Costs		OPEB Costs
Net actuarial loss	$	35.4	$	1.0
Prior service costs (credits)	1.1		(1.1		)
Total 2017 – estimated amortization	$	36.5	$	(0.1	)

The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows:



	Pension Costs									OPEB Costs
(in millions)	2016			2015			2014			2016			2015			2014
Service cost	$	10.5		$	14.7		$	9.4		$	7.3		$	9.0		$	8.1
Interest cost	49.7			52.9			59.3			13.2			13.4			14.4
Expected return on plan assets	(77.7		)	(83.6		)	(79.1		)	(14.0		)	(16.0		)	(16.2		)
Amortization of prior service cost (credit)	1.6			2.0			2.0			(1.1		)	(1.1		)	(1.7		)
Amortization of net actuarial loss	32.4			35.6			26.9			1.0			1.0			0.2
Net periodic benefit cost	$	16.5		$	21.6		$	18.5		$	6.4		$	6.3		$	4.8

The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:



	Pension		OPEB
	2016	2015	2016	2015
Discount rate	4.15%	4.45%	4.20%	4.45%
Rate of compensation increase	3.20%	4.00%	N/A	N/A
Assumed medical cost trend rate	N/A	N/A	7.00%	7.50%
Ultimate trend rate	N/A	N/A	5.00%	5.00%
Year ultimate trend rate is reached	N/A	N/A	2021	2021

The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:



	Pension Costs
	2016	2015	2014
Discount rate	4.45%	4.15%	5.00%
Expected return on plan assets	7.00%	7.00%	7.25%
Rate of compensation increase	3.50%	4.00%	4.00%



	OPEB Costs
	2016	2015	2014
Discount rate	4.45%	4.20%	4.95%
Expected return on plan assets	7.25%	7.25%	7.50%
Assumed medical cost trend rate (Pre 65/Post 65)	7.50%	7.50%	7.50%
Ultimate trend rate	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2021	2021	2021

WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2017, the expected return on assets assumption is 7.00% for the pension plan and 7.25% for the OPEB plan.



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Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2016, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:



(in millions)	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	2.9	$	(2.3	)
Effect on the health care component of the accumulated postretirement benefit obligation	31.5		(26.0		)

Plan Assets

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

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

Our pension trust target asset allocation is 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The OPEB trusts' target asset allocations are 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.

Pension and OPEB plan investments are recorded at fair value. See Note 1(n), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. Following our adoption of ASU 2015-07 on January 1, 2016, the assets that are not subject to leveling are investments that are valued using the net asset value per share (or its equivalent) practical expedient. We have applied this approach retrospectively to the 2015 table for comparability.

The following table summarizes the fair values of our investments by asset class:



	December 31, 2016
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	1.1	$	19.2	$	—	$	20.3	$	6.5	$	1.3	$	—	$	7.8
Equity securities:
Unites States Equity	85.5		0.1		—		85.6		10.5		—		—		10.5
International Equity	17.7		—		—		17.7		1.3		—		—		1.3
Fixed income securities: *
United States Bonds	—		455.3		—		455.3		—		44.0		—		44.0
International Bonds	—		31.6		—		31.6		—		2.8		—		2.8
Private Equity and Real Estate	—		—		11.0		11.0		—		—		0.7		0.7
	$	104.3	$	506.2	$	11.0	$	621.5	$	18.3	$	48.1	$	0.7	$	67.1
Investments measured at net asset value							$	481.3							$	138.0
Total	$	104.3	$	506.2	$	11.0	$	1,102.8	$	18.3	$	48.1	$	0.7	$	205.1


*	This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.



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	December 31, 2015
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	15.5	$	—	$	—	$	15.5	$	2.4	$	—	$	—	$	2.4
Equity securities:
United States equity	80.1		—		—		80.1		11.8		—		—		11.8
International equity	25.8		—		—		25.8		1.7		—		—		1.7
Fixed income securities: *
United States bonds	—		509.4		—		509.4		—		78.1		—		78.1
International bonds	—		32.6		—		32.6		—		4.5		—		4.5
Private Equity and Real Estate	—		—		4.5		4.5		—		—		0.3		0.3
	$	121.4	$	542.0	$	4.5	$	667.9	$	15.9	$	82.6	$	0.3	$	98.8
Investments measured at net asset value							$	511.4							$	117.3
Total	$	121.4	$	542.0	$	4.5	$	1,179.3	$	15.9	$	82.6	$	0.3	$	216.1


*	This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.

The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy:



	Private Equity and Real Estate
(in millions)	Pension		OPEB
Beginning balance at January 1, 2016	$	4.5	$	0.3
Purchases	6.5		0.4
Ending balance at December 31, 2016	$	11.0	$	0.7



	Private Equity and Real Estate
(in millions)	Pension		OPEB
Beginning balance at January 1, 2015	$	—	$	—
Purchases	4.5		0.3
Ending balance at December 31, 2015	$	4.5	$	0.3

Cash Flows

We expect to contribute $4.9 million to the pension plans in 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. We do not expect to contribute to the OPEB plans in 2017.

The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB:



(in millions)	Pension Costs		OPEB Costs
2017	$	90.7	$	13.3
2018	88.6		14.4
2019	86.6		15.3
2020	86.5		16.1
2021	82.7		16.8
2022-2026	381.1		89.3

Savings Plans

We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. Total costs incurred under these plans were $10.4 million in 2016, and $13.0 million in both 2015 and 2014.



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NOTE 16—COMMITMENTS AND CONTINGENCIES

We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, operating leases, environmental matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates.

The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2016.



				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2017		2018		2019		2020		2021		Later Years
Electric utility:
Nuclear	2033	$	9,599.8	$	415.3	$	420.1	$	445.4	$	475.1	$	501.1	$	7,342.8
Coal supply and transportation	2019	313.1		183.6		97.5		32.0		—		—		—
Purchased power	2031	86.0		30.5		21.7		9.2		6.9		5.9		11.8
Natural gas utility supply and transportation	2024	217.2		56.3		49.3		43.0		31.5		17.9		19.2
Total		$	10,216.1	$	685.7	$	588.6	$	529.6	$	513.5	$	524.9	$	7,373.8

Operating Leases

We lease property, plant, and equipment under various terms. The operating leases generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value, or (b) exercise a renewal option, as set forth in the lease agreement.

Rental expense attributable to operating leases was $5.0 million, $6.7 million, and $4.8 million in 2016, 2015, and 2014, respectively.

Future minimum payments under noncancelable operating leases are payable as follows:



Year Ending December 31	Payments (in millions)
2017	$	4.4
2018	3.3
2019	1.4
2020	1.3
2021	1.4
Later years	21.7
Total	$	33.5

Environmental Matters

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

We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:


•	the development of additional sources of renewable electric energy supply;



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•	the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;


•	the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules;


•	the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects;


•	the retirement of old coal-fired power plants and conversion to modern, efficient, natural gas generation and super-critical pulverized coal generation;


•	the beneficial use of ash and other products from coal-fired and biomass generating units; and


•	the remediation of former manufactured gas plant sites.

Air Quality

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO₂ that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets discussed below apply to 2017 and beyond.

In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and issued the final rule in September 2016. Starting in 2017, this rule requires reductions in the ozone season (May 1 through September 30) NOxemissions from power plants in 23 states in the eastern United States, including Wisconsin. The EPA updated Phase II CSAPR NOxozone season budgets for electric generating units in the affected states. In the final rule, the EPA significantly increased the NOx ozone season budget from the proposed rule for Wisconsin starting in 2017. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.

Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour SO₂ NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.

In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO₂. The consent decree required the EPA to complete attainment designations for certain areas with large sources by no later than July 2016. SO₂emissions from PIPP are above the consent decree emission threshold, which means that the Marquette area required action earlier than would otherwise have been required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. In July 2016, the EPA finalized its recommendation and published a notice in the Federal Register designating Marquette County, Michigan as unclassified/attainment, effective September 2016.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

8-Hour Ozone National Ambient Air Quality Standards

The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.



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Mercury and Other Hazardous Air Pollutants

In December 2011, the EPA issued the final MATS rule, which imposed stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the Supreme Court ruled on a challenge to the MATS rule and remanded the case back to the D.C. Circuit Court of Appeals, ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule remains in effect until the D.C. Circuit Court of Appeals takes action on the EPA's April 2016 updated cost evaluation.

We believe that our fleet is well positioned to comply with the final MATS rule and do not expect to incur any significant additional costs to comply with this regulation. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, allowing PIPP to be in compliance with MATS.

Climate Change

In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the Clean Power Plan until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The D.C. Circuit Court of Appeals heard the case in September 2016.

The final rule for existing fossil-fueled generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. We continue to evaluate possible reduction opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions, given the uncertain future of the Clean Power Plan and current fuel and technology markets. Our evaluation to date indicates that the Clean Power Plan, as well as current fuel markets and advances in technology, are not expected to result in significant additional compliance costs, including capital expenditures, but could impact how we operate our existing fossil-fueled power plants and biomass facility.

However, the timelines for the 2022 through 2029 interim goals and the 2030 final goal for states, as well as all other aspects of the rule, likely will be changed due to the stay and subsequent legal proceedings. With the new Federal Executive Administration as of January 2017, the Clean Power Plan, or its successor, could be significantly changed from the final rule of October 2015. Notwithstanding the potential changes to the Clean Power Plan, addressing climate change is an integral component of our strategic planning process. We continue to reshape our portfolio of electric generation facilities with investments that will improve our environmental performance, including reduced GHG intensity of our operating fleet. As the regulation of GHG emissions takes shape, our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO₂ emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO₂ reduction goal, such as increased utilization of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.

Draft Federal Plan and Model Trading Rules (Model Rules) were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for reconsideration of the EPA's final standards for existing, as well as for new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly asked the EPA to consider revising the state goal for existing units to reflect the 2013



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retirement of the Kewaunee Power Station, which could lower the state's CO₂equivalent reduction goal by about 10%. In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. The EPA has not issued decisions yet regarding the above referenced petitions for reconsideration of the final EPA standards for existing generating units. In December 2016, the EPA withdrew the draft Model Rules and accompanying draft documents from the review process and made working drafts available to the public. They are not final documents, are not signed by the Administrator, and will not be published in the Federal Register. The EPA’s docket will remain open, with the potential for completing the agency’s work on these materials and finalizing them at a later date.

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2015, we reported aggregated CO₂ equivalent emissions of approximately 25.3 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 23.9 million metric tonnes to the EPA for 2016. The level of CO₂ and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO₂ equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2015, we reported aggregated CO₂ equivalent emissions of approximately 3.8 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 3.7 million metric tonnes to the EPA for 2016.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements.

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for PWGS, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8.

During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towers that meet EM BTA requirements) and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies were recently completed at PIPP. See UMERC discussion in Note 20, Regulatory Environment, regarding the potential retirement of PIPP.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.



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Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. This rule is being litigated in the United States Court of Appeals for the Fifth Circuit and may result in changes to the discharge requirements. The WDNR and MDEQ will continue to modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications will be required at OC 7, OC 8, and the Pleasant Prairie units. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $55 million to $75 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See UMERC discussion in Note 20, Regulatory Environment, regarding the potential retirement of PIPP.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31:



(in millions)	2016		2015
Regulatory assets	$	29.9	$	16.9
Reserves for future remediation	19.0		5.6

Renewables, Efficiency, and Conservation

Wisconsin Legislation

In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. We have achieved a renewable energy percentage of 8.27% and met our compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolios and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual operating revenues.

Michigan Legislation

In 2008, Michigan enacted Act 295, which required 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. In December 2016, Michigan revised this legislation with Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the



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requirement to 15.0% for 2021. We were in compliance with these requirements as of December 31, 2016. The revised legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

Enforcement and Litigation Matters

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.

Paris Generating Station Units 1 and 4 Construction Permit

In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to Paris Generating Station Units 1 and 4. Act 91, along with a new construction permit, allowed those units to restart after a temporary outage. In October 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit. In February 2013, the Sierra Club also filed for a contested case hearing with the WDNR in connection with the administration order issued in this matter, which was granted. The Sierra Club has withdrawn the contested case hearing request, thereby concluding this matter.

NOTE 17—FAIR VALUE MEASUREMENTS

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:



	December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	6.0	$	0.8	$	—	$	6.8
Petroleum products contracts	0.2		—		—		0.2
FTRs	—		—		3.1		3.1
Coal contracts	—		1.9		—		1.9
Total derivative assets	$	6.2	$	2.7	$	3.1	$	12.0

Derivative liabilities
Natural gas contracts	$	0.1	$	—	$	—	$	0.1
Petroleum products contracts	0.1		—		—		0.1
Coal contracts	—		0.5		—		0.5
Total derivative liabilities	$	0.2	$	0.5	$	—	$	0.7



	December 31, 2015
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.5	$	—	$	—	$	0.5
Petroleum products contracts	1.2		—		—		1.2
FTRs	—		—		1.6		1.6
Coal contracts	—		2.0		—		2.0
Total derivative assets	$	1.7	$	2.0	$	1.6	$	5.3

Derivative liabilities
Natural gas contracts	$	9.2	$	0.2	$	—	$	9.4
Petroleum products contracts	4.4		—		—		4.4
Coal contracts	—		7.6		—		7.6
Total derivative liabilities	$	13.6	$	7.8	$	—	$	21.4



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The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 18, Derivative Instruments, for more information.

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



(in millions)	2016			2015			2014
Balance at the beginning of the period	$	1.6		$	7.0		$	3.5
Purchases	8.1			3.9			15.6
Settlements	(6.6		)	(9.3		)	(12.1		)
Balance at the end of the period	$	3.1		$	1.6		$	7.0

Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on our income statements.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:



	December 31, 2016				December 31, 2015
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	28.8	$	30.4	$	27.3
Long-term debt	2,661.1		2,923.4		2,658.8		2,888.2

NOTE 18—DERIVATIVE INSTRUMENTS

The following table shows our derivative assets and derivative liabilities:



	December 31, 2016				December 31, 2015
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	6.3	$	0.1	$	0.5	$	8.1
Petroleum products contracts	0.2		0.1		0.9		3.3
FTRs	3.1		—		1.6		—
Coal contracts	1.5		0.5		1.7		3.4
Total other current	$	11.1	$	0.7	$	4.7	$	14.8

Other long-term
Natural gas contracts	$	0.5	$	—	$	—	$	1.3
Petroleum products contracts	—		—		0.3		1.1
Coal contracts	0.4		—		0.3		4.2
Total other long-term	$	0.9	$	—	$	0.6	$	6.6
Total	$	12.0	$	0.7	$	5.3	$	21.4

Our estimated notional sales volumes and realized gains (losses) were as follows:



	December 31, 2016				December 31, 2015				December 31, 2014
(in millions)	Volume	Gains (Losses)			Volume	Gains (Losses)			Volume	Gains
Natural gas contracts	35.3 Dth	$	(12.3	)	24.0 Dth	$	(12.6	)	21.4 Dth	$	4.0
Petroleum products contracts	10.3 gallons	(2.6		)	4.0 gallons	(0.2		)	9.2 gallons	0.5
FTRs	25.3 MWh	7.3			22.8 MWh	3.2			26.1 MWh	12.7
Total		$	(7.6	)		$	(9.6	)		$	17.2

At December 31, 2016, we had received cash collateral of $3.4 million in our margin accounts, and at December 31, 2015, we had posted cash collateral of $14.9 million in our margin accounts.



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The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:



	December 31, 2016						December 31, 2015
(in millions)	Derivative Assets			Derivative Liabilities			Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	12.0		$	0.7		$	5.3		$	21.4
Gross amount not offset on the balance sheet *	(3.6		)	(0.2		)	(0.7		)	(13.5		)
Net amount	$	8.4		$	0.5		$	4.6		$	7.9


*	Includes cash collateral received of $3.4 million at December 31, 2016, and cash collateral posted of $12.8 million at December 31, 2015.

NOTE 19—VARIABLE INTEREST ENTITIES

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis. This ASU focuses on the consolidation analysis for companies that are required to evaluate whether they should consolidate certain legal entities. It emphasizes the risk of loss when determining a controlling financial interest and amends the guidance for assessing how related party relationships affect the consolidation analysis of variable interest entities. We adopted the standard upon its effective date in the first quarter of 2016, and our adoption resulted in no changes to our disclosures or financial statement presentation.

The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.

We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

American Transmission Company

As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. Prior to the transfer, ATC was a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 5, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheets at December 31, 2016, included our equity investment and accounts payable. At December 31, 2016, and 2015, our equity investment was $402.0 million and $382.2 million, respectively, which approximated our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $20.0 million and $19.9 million of accounts payable due to ATC at December 31, 2016, and 2015, respectively, for network transmission services.

Purchased Power Agreement

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

We have approximately $85.3 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the years ended December 31, 2016, 2015, and 2014 were $54.2 million, $53.6 million, and $53.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.



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NOTE 20—REGULATORY ENVIRONMENT

2015 Wisconsin Rate Order

In May 2014, we applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved the following rate adjustments, effective January 1, 2015:

•

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


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


•	A rate decrease of $13.9 million (-0.5%) in 2015 related to a forecasted decrease in fuel costs.


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


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


•	A rate increase of approximately $1.2 million (7.3%) for our Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016. As a result of the sale of the MCPP, we no longer have any Milwaukee County steam utility customers. See Note 3, Dispositions, for more information about the sale of the MCPP.

Our authorized ROE was set at 10.2%, and our common equity component remained at an average of 51%. The PSCW order reaffirmed the deferral of our transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW approved a change in rate design for us, which included higher fixed charges to better match the related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues we will receive under the PIPP SSR agreements. Under escrow accounting, we record SSR revenues of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference is deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference is deferred and will be recovered from customers with interest, in a future rate case.

In January 2015, certain parties appealed a portion of the PSCW's final decision adopting our specific rate design changes, including new charges for customer-owned generation within our service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in our rate case to support a demand charge for customer-owned generation. As a result, this demand charge did not take effect on January 1, 2016. No other rates approved by the PSCW in the rate case were impacted by the Dane County Circuit Court order.

Earnings Sharing Agreement

In May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for us. See Note 2, Acquisitions, for more information on this earnings sharing mechanism.

2013 Wisconsin Rate Order

In March 2012, we initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved the following rate adjustments, effective January 1, 2013:

•

A net bill increase related to non-fuel costs for our retail electric customers of approximately $70.0 million (2.6%) in 2013. This amount reflected an offset of approximately $63.0 million (2.3%) for bill credits related to the proceeds of the Treasury Grant, including associated tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133.0 million (4.8%) in 2013.


•	An electric rate increase for our electric customers of approximately $28.0 million (1.0%) in 2014, and a $45.0 million (-1.6%) reduction in bill credits.


•	Recovery of a forecasted increase in fuel costs of approximately $44.0 million (1.6%) in 2013.



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•	A rate decrease of approximately $8.0 million (-1.9%) for our natural gas customers in 2013, with no rate adjustment in 2014. The rates reflected a $6.4 million reduction in bad debt expense.


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


•	An increase of approximately $1.0 million (7.0%) in 2013 and $1.0 million (6.0%) in 2014 for our Milwaukee County steam utility customers.

Based on the PSCW order, our authorized ROE remained at 10.4%. In addition, the PSCW approved escrow accounting treatment for the Treasury Grant. The PSCW also determined the construction costs for the ERGS units were prudently incurred, and it approved the recovery of the majority of these costs in rates.

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand-alone utility in the Upper Peninsula of Michigan and it became operational effective January 1, 2017. This utility holds our and WPS's electric and natural gas distribution assets located in the Upper Peninsula.

In August 2016, WEC Energy Group entered into an agreement with the Tilden Mining Company (Tilden) under which it will purchase electric power from UMERC for its iron ore mine for 20 years. The agreement also calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation located in the Upper Peninsula of Michigan. On January 30, 2017, UMERC filed an application with the MPSC for a certificate of necessity to begin construction of the proposed generation. The estimated cost of this project is approximately $265 million ($275 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain our customer until this new generation begins commercial operation.

NOTE 21—SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2016, we reported two segments, which are described below.

Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, northern Wisconsin, and the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden Mining Company. See Note 4, Related Parties, and Note 20, Regulatory Environment, for additional information. Our electric utility operations also include our steam operations which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.

At December 31, 2016, our other segment included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and Bostco, our non-utility subsidiary, that develops and invests in real estate. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information.



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All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2016, 2015, and 2014.



2016 (in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Operating revenues	$	3,792.8	$	—	$	3,792.8
Other operation and maintenance	1,430.2		—		1,430.2
Depreciation and amortization	325.4		—		325.4
Operating income	629.5		—		629.5
Equity in earnings of transmission affiliate	—		55.5		55.5
Interest expense	116.6		1.0		117.6
Capital expenditures	468.9		0.6		469.5
Total assets	12,945.1		426.4		13,371.5



2015 (in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Operating revenues	$	3,854.1	$	—	$	3,854.1
Other operation and maintenance	1,384.9		—		1,384.9
Depreciation and amortization	304.0		—		304.0
Operating income	648.9		—		648.9
Equity in earnings of transmission affiliate	—		47.8		47.8
Interest expense	117.7		1.3		119.0
Capital expenditures	518.8		0.4		519.2
Total assets	12,727.6		412.0		13,139.6



2014 (in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Operating revenues	$	4,059.4	$	—	$	4,059.4
Other operation and maintenance	1,356.4		—		1,356.4
Depreciation and amortization	278.3		—		278.3
Operating income	650.4		—		650.4
Equity in earnings of transmission affiliate	—		57.9		57.9
Interest expense	114.9		1.6		116.5
Capital expenditures	561.8		—		561.8
Total assets	12,195.9		401.3		12,597.2

NOTE 22—QUARTERLY FINANCIAL INFORMATION (Unaudited)



(in millions)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2016
Operating revenues	$	975.5	$	877.2	$	1,023.8	$	916.3	$	3,792.8
Operating income	181.5		146.9		196.4		104.7		629.5
Net income attributed to common shareholder	107.3		82.6		115.2		59.2		364.3

2015
Operating revenues	$	1,084.6	$	883.0	$	981.1	$	905.4	$	3,854.1
Operating income	204.7		128.7		169.8		145.7		648.9
Net income attributed to common shareholder	121.4		74.6		100.1		79.6		375.7

Due to various factors, the quarterly results of operations are not necessarily comparable.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the



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guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. This method will result in a cumulative-effect adjustment that will be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. Disclosures in 2018 will include a reconciliation of results under the new revenue guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.

We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider our tariff sales, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry, including the impacts of the new guidance on our ability to recognize revenue for certain contracts where collectability is uncertain and the accounting for contributions in aid of construction (CIAC). We currently account for CIAC funds received from customers and/or developers outside of revenue, as a reduction to property, plant, and equipment. The final resolution of these issues could impact our current accounting policies and revenue recognition.

Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We are currently assessing the effects this guidance may have on our financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements.

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Under this ASU, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement, the tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur, and excess tax benefits are recognized in the current period regardless of whether the benefit reduces taxes payable. On the cash flow statement, excess tax benefits are classified along with other income tax cash flows as an operating activity, and cash paid by an employer when directly withholding shares for tax purposes is classified as a financing activity. We adopted this guidance effective January 1, 2017, and do not expect it to impact our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for

fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally



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delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.

Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We are currently assessing the effects this guidance may have on our financial statements.



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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our 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 our internal control over financial reporting was effective as of December 31, 2016.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us 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 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.



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PART III

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

The information under "Election of Directors", "Section 16(a) Beneficial Ownership Reporting Compliance", "Corporate Governance – Frequently Asked Questions: What is the process used to identify director nominees and how do I recommend a nominee to WEC Energy Group's Corporate Governance Committee?", "Corporate Governance – Frequently Asked Questions: Are the WEC Energy Group Audit and Oversight and Compensation Committees comprised solely of independent directors?", "Corporate Governance – Frequently Asked Questions: Are all the members of the WEC Energy Group Audit Committee financially literate and does the committee have an 'audit committee financial expert'?", "Corporate Governance – Frequently Asked Questions: Does the Board have a nominating committee?", and "Committees of the WEC Energy Group Board of Directors – Audit and Oversight" in our Definitive Information Statement on Schedule 14C to be filed with the SEC for our Annual Meeting of Stockholders to be held April 27, 2017 (the "2017 Annual Meeting Information Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.

WEC Energy Group has adopted a written code of ethics, referred to as its Code of Business Conduct. We are a subsidiary of WEC 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 WEC Energy Group's Code of Business Conduct. WEC Energy Group has posted its Code of Business Conduct in the "Governance" section on its website, www.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 WEC Energy Group's website or in a current report on Form 8-K.

ITEM 11. EXECUTIVE COMPENSATION

The information under "Compensation Discussion and Analysis", "Executive Compensation", "Director Compensation", "Committees of the WEC Energy Group Board of Directors – Compensation", "Compensation Committee Report", "Risk Analysis of Compensation Policies and Practices", and "Certain Relationships and Related Transactions – Compensation Committee Interlocks and Insider Participation" in the 2017 Annual Meeting Information Statement is incorporated herein by reference.

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

All of our Common Stock is owned by our parent company, WEC Energy Group, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201. Our directors and director nominees, who 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 WEC Energy Group common stock set forth under "Stock Ownership of Directors, Nominees and Executive Officers" in the 2017 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 WEC Energy Group.

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 2017 Annual Meeting Information Statement is incorporated herein by reference. A full description of the guidelines the WEC Energy Group Board uses to determine director independence is located in Appendix A of WEC Energy Group's Corporate Governance Guidelines, which can be found on its website, www.wecenergygroup.com.



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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 2017 Annual Meeting Information Statement is incorporated herein by reference.



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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



1.	Financial Statements and Reports of Independent Registered Public Accounting Firm Included in Part II of This Report

	Description	Page in 10-K

	Report of Independent Registered Public Accounting Firm.	47

	Consolidated Income Statements for the three years ended December 31, 2016, 2015, and 2014.	48

	Consolidated Balance Sheets at December 31, 2016 and 2015.	49

	Consolidated Statements of Cash Flows for the three years ended December 31, 2016, 2015, and 2014.	50

	Consolidated Statements of Equity for the three years ended December 31, 2016, 2015, and 2014.	51

	Consolidated Statements of Capitalization at December 31, 2016 and 2015.	52

	Notes to Consolidated Financial Statements.	53

2.	Financial Statement Schedules Included in Part IV of This Report

	Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2016, 2015, and 2014.	93

	Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.

3.	Exhibits and Exhibit Index

	See the Exhibit Index included as the last part of this report, which is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the Exhibit Index by two asterisks (**) following the description of the exhibit.	95

ITEM 16. FORM 10-K SUMMARY

None.



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SCHEDULE II

WISCONSIN ELECTRIC POWER COMPANY

VALUATION AND QUALIFYING ACCOUNTS



Allowance for Doubtful Accounts (in millions)	Balance at Beginning of Period		Expense ⁽¹⁾		Deferral			Net Write-offs ⁽²⁾			Balance at End of Period
December 31, 2016	$	43.0	$	31.1	$	(5.7	)	$	(27.5	)	$	40.9
December 31, 2015	46.8		30.6		0.3			(34.7		)	43.0
December 31, 2014	39.7		31.3		10.0			(34.2		)	46.8


⁽¹⁾	Net of recoveries


⁽²⁾	Represents amounts written off to the reserve, net of adjustments to regulatory assets.



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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/ ALLEN L. LEVERETT
Date:	February 28, 2017	Allen L. Leverett, 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/ ALLEN L. LEVERETT		February 28, 2017
Allen L. Leverett, Chairman of the Board and Chief Executive
Officer and Director -- Principal Executive Officer

/s/ SCOTT J. LAUBER		February 28, 2017
Scott J. Lauber, Executive Vice President and Chief
Financial Officer and Director -- Principal Financial Officer

/s/WILLIAM J. GUC		February 28, 2017
William J. Guc, Vice President and
Controller -- Principal Accounting Officer

/s/J. KEVIN FLETCHER		February 28, 2017
J. Kevin Fletcher, Director

/s/SUSAN H. MARTIN		February 28, 2017
Susan H. Martin, Director



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WISCONSIN ELECTRIC POWER COMPANY

(Commission File No. 001-01245)

EXHIBIT INDEX

Annual Report on Form 10-K

For the year ended December 31, 2016

The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)



Number	Exhibit
3	Articles of Incorporation and By-laws

	3.1*	Restated Articles of Incorporation of WE, as amended and restated effective January 10, 1995. (Exhibit (3)-1 to WE's 12/31/94 Form 10-K.)

	3.2*	Bylaws of WE, as amended to May 1, 2000. (Exhibit 3.1 to WE's 03/31/00 Form 10-Q.)

4	Instruments defining the rights of security holders, including indentures

	4.1*	Reference is made to Article III of the Restated Articles of Incorporation of Wisconsin Electric Power Company. (Exhibit 3.1 to WE's 12/31/16 Form 10-K.)

	Indentures and Securities Resolutions:

	4.2*	Indenture for Debt Securities of WE (the "WE Indenture"), dated December 1, 1995. (Exhibit (4)-1 to WE's 12/31/95 Form 10-K.)

	4.3*	Securities Resolution No. 1 of WE under the WE Indenture, dated December 5, 1995. (Exhibit (4)-2 to WE's 12/31/95 Form 10-K.)

	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.)

	4.5*	Securities Resolution No. 5 of WE under the WE Indenture, dated as of May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to WE's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)

	4.6*	Securities Resolution No. 7 of WE under the WE Indenture, dated as of November 2, 2006. (Exhibit 4.1 to WE's 11/02/06 Form 8-K.)

	4.7*	Securities Resolution No. 10 of WE under the WE Indenture, dated as of December 8, 2009. (Exhibit 4.1 to WE's 12/08/09 Form 8-K.)

	4.8*	Securities Resolution No. 11 of WE under the WE Indenture, dated as of September 7, 2011. (Exhibit 4.1 to WE's 09/07/11 Form 8-K.)

	4.9*	Securities Resolution No. 12 of WE under the WE Indenture, dated as of December 5, 2012. (Exhibit 4.1 to WE's 12/05/12 Form 8-K.)

	4.10*	Securities Resolution No. 13 of WE under the WE Indenture, dated as of June 10, 2013. (Exhibit 4.1 to WE’s 06/10/13 Form 8-K.)

	4.11*	Securities Resolution No. 14 of WE under the WE Indenture, dated as of May 12, 2014. (Exhibit 4.1 to WE's 05/12/14 Form 8-K.)

	4.12*	Securities Resolution No. 15 of WE under the WE Indenture, dated as of May 14, 2015. (Exhibit 4.1 to WE's 05/14/15 Form 8-K.)



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Number	Exhibit
	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*	WEC Energy Group Supplemental Pension Plan, Amended and Restated Effective as of January 1, 2017. (Exhibit 10.1 to WEC Energy Group's 12/31/16 Form 10-K (File No. 001-09057).)** See Note.

	10.2*	Legacy WEC Energy Group Executive Deferred Compensation Plan, Amended and Restated as of January 1, 2016. (Exhibit 10.2 to WEC Energy Group's 12/31/15 Form 10-K (File No. 001-09057).)** See Note

	10.3*	WEC Energy Group Executive Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2017. (Exhibit 10.3 to WEC Energy Group's 12/31/16 Form 10-K (File No. 001-09057).)** See Note.

	10.4*	Legacy Wisconsin Energy Corporation Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2017. (Exhibit 10.4 to WEC Energy Group's 12/31/16 Form 10-K (File No. 001-09057).)** See Note.

	10.5*	WEC Energy Group Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2017. (Exhibit 10.5 to WEC Energy Group's 12/31/16 Form 10-K (File No. 001-09057).)** See Note.

	10.6*	WEC Energy Group Non-Qualified Retirement Savings Plan, Amended and Restated Effective as of January 1, 2017. (Exhibit 10.6 to WEC Energy Group's 12/31/16 Form 10-K (File No. 001-09057).)** See Note.

	10.7*	WEC Energy Group Short-Term Performance Plan, as amended and restated effective as of January 1, 2016. (Exhibit 10.2 to WEC Energy Group's 12/03/15 Form 8-K (File No. 001-09057).)** See Note.

	10.8*	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.

	10.9*	Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Gale E. Klappa, dated as of December 29, 2008. (Exhibit 10.25 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.10*	Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Allen L. Leverett, dated as of December 30, 2008. (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.11*	Terms of Employment for J. Patrick Keyes. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/12 Form 10-Q (File No. 001-09057).)** See Note.

	10.12*	Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of December 20, 2010. (Exhibit 10.20 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.

	10.13*	Amendment to the Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of August 15, 2011. (Exhibit 10.21 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.

	10.14*	Terms of Employment for Susan H. Martin. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/12 Form 10-Q (File No. 001-09057).)**See Note.

	10.15*	Letter Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q (File No. 001-09057).)** See Note.



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Number	Exhibit
	10.16*	Letter Agreement by and between Wisconsin Energy Corporation and Joseph Kevin Fletcher, dated as of August 17, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/11 Form 10-Q (File No. 001-09057).)** See Note.

	10.17*	1993 Omnibus Stock Incentive Plan, Amended and Restated Effective as of January 1, 2016. (Exhibit 10.19 to WEC Energy Group's 12/31/15 Form 10-K (File No. 001-09057).)** See Note.

	10.18*	2005 Terms and Conditions Governing Non-Qualified Stock Option Award under 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/28/04 Form 8-K (File No. 001-09057).)** See Note.

	10.19*	Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/07 Form 10-Q (File No. 001-09057).)** See Note.

	10.20*	Terms and Conditions Governing Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan, approved December 1, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/01/10 Form 8-K (File No. 001-09057).)** See Note.

	10.21*	Wisconsin Energy Corporation Terms and Conditions Governing Director Restricted Stock Award under the 1993 Omnibus Stock Incentive Plan (Exhibit 10.1 to Wisconsin Energy Corporation's 01/19/12 Form 8-K (File No. 001-09057).)** See Note.

	10.22*	WEC Energy Group Performance Unit Plan, amended and restated effective as of January 1, 2017. (Exhibit 10.1 to WEC Energy Group's 12/01/16 Form 8-K (File No. 001-09057).)** See Note.

	10.23*	Wisconsin Energy Corporation Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.

	10.24*	2016 WEC Energy Group Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.27 to WEC Energy Group’s 12/31/15 Form 10-K (File No. 001-09057).)** See Note.

	10.25*	Wisconsin Energy Corporation Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.

	10.26*	2016 WEC Energy Group Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.29 to WEC Energy Group’s Form 12/31/15 Form 10-K (File No. 001-09057).)** See Note.

	10.27*	Port Washington I Facility Lease Agreement between Port Washington Generating Station LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.7 to WE's 06/30/03 Form 10-Q.)

	10.28*	Port Washington II Facility Lease Agreement between Port Washington Generating Station LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.8 to WE's 06/30/03 Form 10-Q.)

	10.29*	Elm Road I Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

	10.30*	Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

	10.31*	Point Beach Nuclear Plant Power Purchase Agreement between FPL Energy Point Beach, LLC and Wisconsin Electric Power Company, dated as of December 19, 2006 (the "PPA"). (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/08 Form 10-Q (File No. 001-09057).)

	10.32*	Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC, dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K (File No. 001-09057).)

	10.33*	Terms and Conditions for July 31, 2015 Special Restricted Stock Award. (Exhibit 10.1 to WEC Energy Group’s 6/30/15 Form 10-Q (File No. 001-09057).)** See Note.



2016 Form 10-K	97	Wisconsin Electric Power Company

Table of Contents



Number	Exhibit

	Note: Two asterisks (**) identify management contracts and executive compensation plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of Form 10-K.

21	Subsidiaries of the registrant

	21.1	Subsidiaries of Wisconsin Electric Power Company.

31	Rule 13a-14(a)/15d-14(a) Certifications

	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications

	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Interactive Data File



2016 Form 10-K	98	Wisconsin Electric Power Company