WISCONSIN ELECTRIC POWER CO - FORM 10-K

Attached files

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EX-32.2 - WISCONSIN ELECTRIC EXHIBIT 32.2 - WISCONSIN ELECTRIC POWER CO	wepco12312015ex322.htm
EX-21.1 - WISCONSIN ELECTRIC EXHIBIT 21.1 - WISCONSIN ELECTRIC POWER CO	wepco12312015ex211.htm
EX-32.1 - WISCONSIN ELECTRIC EXHIBIT 32.1 - WISCONSIN ELECTRIC POWER CO	wepco12312015ex321.htm
EX-31.1 - WISCONSIN ELECTRIC EXHIBIT 31.1 - WISCONSIN ELECTRIC POWER CO	wepco12312015ex311.htm
EX-31.2 - WISCONSIN ELECTRIC EXHIBIT 31.2 - WISCONSIN ELECTRIC POWER CO	wepco12312015ex312.htm
EX-23.1 - WISCONSIN ELECTRIC EXHIBIT 23.1 - WISCONSIN ELECTRIC POWER CO	wepco12312015ex231.htm

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, 2015



[ ]	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 [X] No [ ]

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, 2015 (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, 2016

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 28, 2016, 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, 2015

TABLE OF CONTENTS



					Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION					1
PART I					3
ITEM 1.	BUSINESS				3
	A.	INTRODUCTION			3
	B.	UTILITY OPERATIONS			3
	C.	REGULATION			12
	D.	ENVIRONMENTAL COMPLIANCE			14
	E.	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					29
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES				29
ITEM 6.	SELECTED FINANCIAL DATA				30
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				31
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				48
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA				49
	A.	Report of Independent Registered Public Accounting Firm			49
	B.	Consolidated Income Statements			50
	C.	Consolidated Balance Sheets			51
	D.	Consolidated Statements of Cash Flows			52
	E.	Consolidated Statements of Equity			53
	F.	Consolidated Statements of Capitalization			54
	G.	Notes to Consolidated Financial Statements			55
		Note 1	Summary of Significant Accounting Policies	55
		Note 2	Acquisition	60
		Note 3	Related Parties	61
		Note 4	Investment in American Transmission Company	62
		Note 5	Supplemental Cash Flow Information	63
		Note 6	Regulatory Assets and Liabilities	63
		Note 7	Property, Plant, and Equipment	64
		Note 8	Asset Retirement Obligations	65
		Note 9	Common Equity	65
		Note 10	Preferred Stock	67
		Note 11	Short-Term Debt and Lines of Credit	67
		Note 12	Long-Term Debt and Capital Lease Obligations	68
		Note 13	Income Taxes	70
		Note 14	Employee Benefits	72
		Note 15	Commitments and Contingencies	76



2015 Form 10-K	i	Wisconsin Electric Power Company

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		Note 16	Fair Value Measurements	83
		Note 17	Derivative Instruments	84
		Note 18	Variable Interest Entities	84
		Note 19	Regulatory Environment	85
		Note 20	Michigan Settlement	86
		Note 21	Segment Information	87
		Note 22	Quarterly Financial Information (Unaudited)	88
		Note 23	New Accounting Pronouncements	88
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE				89
ITEM 9A.	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
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS					93
SIGNATURES					94
EXHIBIT INDEX					95



2015 Form 10-K	ii	Wisconsin Electric Power Company

Table of Contents

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
DATC		Duke-American Transmission Company
Integrys		Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
WBS		WEC Business Services LLC
We Power		W.E. Power, LLC
WEC Energy Group		WEC Energy Group, Inc. (previously known as Wisconsin Energy Corporation)
Wisconsin Gas		Wisconsin Gas LLC

Certain Assets
OC 1		Oak Creek Expansion Unit 1
OC 2		Oak Creek Expansion Unit 2
PIPP		Presque Isle Power Plant
PSGS		Paris Generating Station
PWGS		Port Washington Generating Station
PWGS 1		Port Washington Generating Station Unit 1
PWGS 2		Port Washington Generating Station Unit 2
VAPP		Valley Power Plant

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
FASB		Financial Accounting Standards Board
GAAP		Generally Accepted Accounting Principles
OPEB		Other Postretirement Employee Benefits



2015 Form 10-K	iii	Wisconsin Electric Power Company

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Environmental Terms
Act 141		2005 Wisconsin Act 141
CAA		Clean Air Act
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
WPDES		Wisconsin Pollutant Discharge Elimination System

Measurements
Btu		British Thermal Unit(s)
Dth		Dekatherm(s) (One Dth equals one million Btu)
kW		Kilowatt(s) (One kW equals one thousand Watts)
kWh		Kilowatt-hour(s)
MW		Megawatt(s) (One MW equals one million Watts)
MWh		Megawatt-hour(s)

Other Terms and Abbreviations
ARRs		Auction Revenue Rights
Compensation Committee		Compensation Committee of the Board of Directors of WEC Energy Group
CPCN		Certificate of Public Convenience and Necessity
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
GCRM		Gas Cost Recovery Mechanism
LMP		Locational Marginal Price
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
N/A		Not Applicable
NYMEX		New York Mercantile Exchange
Point Beach		Point Beach Nuclear Power Plant
PTF		Power the Future
ROE		Return on Equity
RTO		Regional Transmission Organization
SSR		System Support Resource
Treasury Grant		Section 1603 Renewable Energy Treasury Grant



2015 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 Securities Exchange Act of 1934, as amended. 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 businesses;


•	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, including the extension of bonus depreciation, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, and energy efficiency mandates;


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



2015 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 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 financial performance of ATC and its corresponding contribution to our earnings, as well as the ability of ATC and DATC to obtain the required approvals for their transmission projects;


•	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 terms and conditions of the governmental and regulatory approvals of WEC Energy Group's acquisition of Integrys that could reduce anticipated benefits and the ability to successfully integrate the operations of the combined company;


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


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


•	Other 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.



2015 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 Michigan's Upper Peninsula. Our three reportable segments are electric utility, natural gas utility, and steam utility, which accounted for 89%, 10%, and 1% of total utility revenues, respectively, in 2015. 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, Acquisition.

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 OPERATIONS

ELECTRIC UTILITY SEGMENT

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, northern Wisconsin, and Michigan's Upper Peninsula.



2015 Form 10-K	3	Wisconsin Electric Power Company

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Electric Utility Operating Statistics

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



	Year Ended December 31
	2015		2014		2013
Operating revenues (in millions)
Residential	$	1,207.6	$	1,199.3	$	1,208.6
Small commercial and industrial	1,035.4		1,052.9		1,048.0
Large commercial and industrial	726.7		637.0		711.9
Other	22.1		23.0		23.4
Total retail revenues	2,991.8		2,912.2		2,991.9
Wholesale	101.4		131.9		143.7
Resale	228.2		264.1		143.2
Other operating revenues	89.6		87.8		28.4
Total	3,411.0		3,396.0		3,307.2
Electric customer choice *	2.4		5.1		1.5
Total operating revenues	$	3,413.4	$	3,401.1	$	3,308.7

Customers – end of year (in thousands)
Residential	1,020.8		1,015.0		1,010.5
Small commercial and industrial	116.0		115.4		114.6
Large commercial and industrial	0.7		0.7		0.7
Other	2.6		2.5		2.6
Total customers	1,140.1		1,133.6		1,128.4

Customers – average (in thousands)	1,136.5		1,130.7		1,126.9


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

Electric Sales

Our electric energy deliveries included supply and distribution sales to retail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier. In 2015, retail electric revenues accounted for 87.6% of total electric operating revenues, while wholesale (including resale) electric revenues accounted for 9.7% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Electric Utility Segment Contribution to Operating Income for information on MWh 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, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities.

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

Large Electric Retail Customers

We provide electric utility service to a diversified base of customers in such industries as mining, paper, foundry, food products and machinery production, health services, governmental, and large retail chains. In February 2015, our largest retail electric customer, the owner of two iron ore mines located in Michigan's Upper Peninsula, returned as a customer after choosing an alternative electric supplier in September 2013. We entered into a special contract with each of the mines to provide full requirements electric service through December 31, 2019. In 2015, we deferred, and we expect to continue to defer, the margin from those sales and will apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding. For more information, see Note 20, Michigan Settlement, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Industry Restructuring.



2015 Form 10-K	4	Wisconsin Electric Power Company

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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 3.4%, 5.3%, and 5.9% of total electric energy sales during 2015, 2014, and 2013, respectively. Wholesale revenues accounted for 3.0%, 3.9%, and 4.3% of total electric operating revenues during 2015, 2014, and 2013, respectively.

Resale

The 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 23.8%, 18.5%, and 13.3% of total electric energy sales during 2015, 2014, and 2013, respectively. Resale revenues accounted for 6.7%, 7.8%, and 4.3% of total electric operating revenues during 2015, 2014, and 2013, respectively.

Electric Sales Growth

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

Electric Generation and Supply Mix

Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to maintain a stable, reliable, and affordable supply of electricity. We supply a significant amount of electricity to our customers from power plants that we own or lease from We Power. We supplement our internally generated power supply with long-term power purchase agreements, including the Point Beach power purchase agreement discussed in Power Purchase Commitments, below and through spot purchases in the MISO Energy Markets.

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⁾
	2015	2014	2013
Coal	3,589	3,707	3,822
Natural gas:
Combined cycle	1,082	1,082	1,082
Steam turbine ⁽²⁾	240	118	—
Natural gas/oil peaking units ⁽³⁾	962	962	962
Renewables ⁽⁴⁾	187	155	155
Total rated capacity by fuel type	6,060	6,024	6,021


⁽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.



2015 Form 10-K	5	Wisconsin Electric Power Company

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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 2016:



	Estimate		Actual
	2016		2015		2014		2013
Company-owned or leased generation units:
Coal	52.2	%	53.5	%	55.2	%	53.6	%
Natural gas:
Combined cycle	15.5	%	13.0	%	8.7	%	10.1	%
Steam turbine	1.1	%	1.4	%	0.2	%	—	%
Natural gas/oil peaking units	0.1	%	0.6	%	0.2	%	0.2	%
Renewables	3.1	%	3.5	%	3.8	%	3.3	%
Total company-owned or leased generation units	72.0	%	72.0	%	68.1	%	67.2	%
Power purchase contracts:
Nuclear	22.7	%	24.5	%	25.4	%	27.1	%
Natural gas	3.3	%	1.7	%	2.1	%	2.1	%
Renewables	1.2	%	1.1	%	2.7	%	3.1	%
Other	0.7	%	0.7	%	0.9	%	0.5	%
Total power purchase contracts	27.9	%	28.0	%	31.1	%	32.8	%
Purchased power from MISO	0.1	%	—	%	0.8	%	—	%
Total purchased power	28.0	%	28.0	%	31.9	%	32.8	%
Total electric utility supply	100.0	%	100.0	%	100.0	%	100.0	%

Coal-Fired Generation

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

Natural Gas-Fired Generation

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

Oil-Fired Generation

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

Renewable Generation

Hydroelectric

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

Wind

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



2015 Form 10-K	6	Wisconsin Electric Power Company

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Biomass

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

Generation from Leased Power The Future Units

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

Electric System Reliability

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

We had adequate capacity through company-owned generation units, leased generating units, and power purchase contracts to meet the MISO calculated planning reserve margin during 2015 and expect to have adequate capacity to meet the planning reserve margin requirements during 2016. However, extremely hot weather, unexpected equipment failure or unavailability across the 15-state MISO market footprint could require us to call upon load management procedures. Load management procedures allow for the reduction of energy use through agreements with customers to directly shut off their equipment or through interruptible service, where customers agree to reduce their load in the case of an emergency interruption.

Fuel and Purchased Power Costs

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

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



	2015		2014		2013
Coal	$	25.25	$	27.68	$	27.97
Natural gas combined cycle	23.44		40.64		32.22
Natural gas/oil peaking units	56.33		129.83		83.95
Purchased power	43.87		47.47		43.74

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.



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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 65% of our estimated natural gas use for electric generation in order to help manage our natural gas price risk. This hedging program is generally implemented on a 36-month forward-looking basis. The results of both of these programs are reflected in the average costs of 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 2016, approximately 86% of our total projected coal requirements of approximately 12 million tons are contracted under fixed-price contracts. See Note 15, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

The annual tonnage amounts contracted for 2016 through 2018 are as follows:



(in thousands)		Annual Tonnage
2016		9,978
2017		6,967
2018		3,583

Coal Deliveries

All of our 2016 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. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas, and Missouri, a region referred to as MISO South. These changes have not had a material impact on our allocation of transmission costs, and we do not expect them to have a material impact in the future. For more information on MISO, see Item 1. Business – C. Regulation.

Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. As of December 31, 2015, our power purchase commitments with unaffiliated parties for the next five years is 1,267 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. In addition, 234 MW per year relates to a long-term power purchase agreement under which we purchase power at a price determined monthly based on a formula tied to a natural gas price index.

Other Matters

Seasonality

Our electric sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the 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.



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Competition

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

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

The retail electric utility market in Michigan remains open to competition with its retail choice program, which allows customers to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service. We continue providing distribution and customer service functions regardless of the customer's power supplier.

Environmental Matters

For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 15, Commitments and Contingencies, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Environmental Matters.

Electric Transmission and Energy Markets

American Transmission Company

ATC is a regional transmission company that owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Minnesota. ATC is expected to provide comparable service to all customers, including 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, 2015, our ownership interest in ATC was approximately 23%. See Note 4, Investment in American Transmission Company, for more information

In April 2011, ATC and Duke Energy announced the creation of a joint venture, DATC, that will seek opportunities to acquire, build, own, and operate new electric transmission infrastructure in North America to address increasing demand for affordable, reliable transmission capacity. In April 2013, DATC acquired a 72% interest in California's Path 15 transmission line. DATC continues to evaluate new projects and opportunities, along with participating in the competitive bidding process on projects it considers viable. These projects are located in the service territories of several different RTOs around the country. On January 20, 2016, the FERC issued an order authorizing ATC to enter into a proposed restructuring involving the creation of three new entities: ATC Holdco, ATC Development, and ATC Development Manager Inc. ATC’s current member owners will have the option to retain their existing ownership interests limited to ATC in Wisconsin and adjacent states or to exchange their current ATC ownership interests for ownership interests in ATC Holdco, which would allow them to participate in ATC's transmission business in Wisconsin and adjacent states, as well as new transmission development projects throughout the U.S.

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, for more information.

NATURAL GAS UTILITY SEGMENT

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
	2015		2014		2013
Operating revenues (in millions)
Residential	$	256.6	$	390.5	$	296.0
Commercial and industrial	118.9		204.5		140.8
Total retail revenues	375.5		595.0		436.8
Transport	16.0		16.8		16.0
Other operating revenues	8.2		2.4		(0.9		)
Total	$	399.7	$	614.2	$	451.9

Customers – end of year (in thousands)
Residential	438.7		435.6		432.1
Commercial and industrial	39.1		38.9		38.6
Transport	0.7		0.6		0.6
Total customers	478.5		475.1		471.3

Customers – average (in thousands)	476.4		472.6		469.7

Natural Gas Deliveries

Our gas therm deliveries include customer-owned transported natural gas. Transported natural gas accounted for approximately 39.0% of the total volumes delivered during 2015, 34.9% during 2014, and 35.4% during 2013. Our peak daily send-out during 2015 was 7.3 million therms on January 7, 2015.

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, educational, food products, real estate, and metal.

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 15, Commitments and Contingencies.

Pipeline Capacity and Storage

The interstate pipelines serving Wisconsin originate in major natural gas producing areas of North America: the Oklahoma and Texas basins, western Canada and the Rocky Mountains. We have contracted for 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 us to manage significant changes in daily demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months when demand is lower and withdraw it in the winter months. As a result, we can contract for less long-line pipeline capacity during periods of peak usage than would otherwise be necessary and can purchase natural gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.

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



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Term Natural Gas Supply

We have contracts for firm supplies with terms of 3–7 months with suppliers for natural gas acquired in the Chicago, Illinois market hub and in the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices.

Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our forecasted design peak-day throughput is 9.5 million therms for the 2015 through 2016 heating season.

Secondary Market Transactions

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

Spot Market Natural Gas Supply

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

Hedging Natural Gas Supply Prices

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

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

Seasonality

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

Our working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through October. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through October. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

Competition

Competition in varying degrees exists between natural gas and other forms of energy available to consumers. A number of our large commercial and industrial customers are dual-fuel customers that are equipped to switch between natural gas and alternate fuels. We are allowed to offer lower-priced natural gas sales and transportation services to dual-fuel customers. Under natural gas



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

Our ability to maintain our share of the industrial dual-fuel market depends on our success and the success of third-party natural gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating competitively 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. It remains uncertain if and when the current economic disincentives for small firm customers to choose an alternative natural gas commodity supplier may be removed such that we begin to face competition for the sale of natural gas to those customers.

STEAM UTILITY SEGMENT

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

Steam Utility Operating Statistics

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

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



	Year Ended December 31
	2015		2014		2013
Operating revenues (in millions)	$	41.0	$	44.1	$	39.6

Pounds of steam sales (in millions)	2,515		2,865		2,750

Customers – Average	430		440		445

C. REGULATION

We are subject to the requirements of the Public Utility Holding Company Act of 2005 as we meet the definition of a holding company under this Act due to our ownership interest in ATC.

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

Rates

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



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



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

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

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

For information on how our rates are set, see Note 19, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:



Regulatory 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:



	2015				2014				2013
(in millions)	Amount		Percent		Amount		Percent		Amount		Percent
Electric
Wisconsin	$	2,829.5	82.9	%	$	2,889.9	85.0	%	$	2,874.8	86.9	%
Michigan	163.0		4.8	%	58.8		1.7	%	147.0		4.4	%
FERC – Wholesale	329.5		9.6	%	396.0		11.6	%	286.9		8.7	%
FERC – SSR *	91.4		2.7	%	56.4		1.7	%	—		—	%
Total	3,413.4		100.0	%	3,401.1		100.0	%	3,308.7		100.0	%

Natural Gas – Wisconsin	399.7		100.0	%	614.2		100.0	%	451.9		100.0	%

Steam – Wisconsin	41.0		100.0	%	44.1		100.0	%	39.6		100.0	%

Total utility operating revenues	$	3,854.1			$	4,059.4			$	3,800.2


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

Electric Transmission, Capacity, and Energy Markets

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



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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 mitigate or eliminate 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, 2015 through May 31, 2016. 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 2015 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 Act 295 in Michigan, which contain certain minimum requirements for renewable energy generation. See Note 15, Commitments and Contingencies, for more information.

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

Other Natural Gas Regulations

Almost all of the 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 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.

D. 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 Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements in Item 7. For a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites, and air and water quality, see Note 15, Commitments and



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Contingencies, and Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Environmental Matters in Item 7.

E. EMPLOYEES

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

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



	Number of Employees	Expiration Date of Current Labor Agreement
Local 2150 of International Brotherhood of Electrical Workers, AFL-CIO	1,679	August 15, 2017
Local 420 of International Union of Operating Engineers, AFL-CIO	489	September 30, 2017
Local 2006 Unit 1 of United Steel Workers of America, AFL-CIO	123	April 30, 2017
Local 510 of International Brotherhood of Electrical Workers, AFL-CIO	105	October 31, 2016
Total	2,396



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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 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 has adopted and has 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 CAA through the NAAQS, the MATS rule, the Clean Power Plan, the CSAPR, and other air quality regulations. In addition, the EPA has 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. Several environmental regulations were either finalized or implemented during 2015, and there is still uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with these regulations.

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

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

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

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

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

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

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



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

There is no guarantee that we will be allowed to fully recover costs incurred to comply with the Clean Power Plan or that cost recovery will not be delayed or otherwise conditioned. The Clean Power Plan and any other related regulations that may be adopted in the future, either at the federal or state level, may cause our environmental compliance spending over the next several years to differ materially from the amounts currently estimated. These regulations could have a material adverse impact on our electric generation and natural gas distribution operations, could make some of our electric generating units uneconomic to maintain or operate, and could affect unit retirement and replacement decisions. These regulations could also adversely affect our future results of operations, cash flows, and financial condition.

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

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

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

Risks Related to the Operation of Our Business

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

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

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



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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. Customers could voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, and individual conservation efforts through the use of more energy efficient technologies. 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 and Michigan, have adopted energy efficiency targets to reduce energy consumption by certain dates.

As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact 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, natural gas storage, 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, the applicable commission may deem the additional capital costs as imprudent and disallow recovery of them through rates.

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

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

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



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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 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 intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission, distribution, and storage 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 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.

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

Inherent in natural gas distribution activities are 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.



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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.

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

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

Risks Related to Economic and Market Volatility

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

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

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


•	A rating downgrade;


•	An economic downturn or uncertainty;



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•	Prevailing market conditions;


•	Concerns over foreign economic conditions;


•	Changes in tax policy;


•	War or the threat of war; and


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

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

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

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

Any downgrade by the rating agencies could:


•	Increase borrowing costs under our existing credit facility;


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


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


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


•	Trigger collateral requirements in various contracts.

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

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

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

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

Changes in commodity prices could result in:


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


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


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


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


•	Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

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

We are dependent on coal for much of our electric generating capacity. Although we generally carry sufficient coal inventory at our generating facilities to protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. The suppliers under these agreements may experience financial or operational problems that inhibit their ability to



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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 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 value of the reported fair value of these contracts.

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

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

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

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 was simultaneously co-optimized with its existing energy markets.

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

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



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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.

Risks Related to the Integrys Acquisition

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

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 PTF generating units.

As of December 31, 2015, 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
Milwaukee County	Wauwatosa, WI	Coal	3	7	⁽²⁾
Oak Creek Expansion	Oak Creek, WI	Coal	2	1,057	⁽³⁾
Pleasant Prairie	Pleasant Prairie, WI	Coal	2	1,188
Presque Isle	Marquette, MI	Coal	5	344
South Oak Creek	Oak Creek, WI	Coal	4	993
Total coal-fired plants			16	3,589
Natural gas-fired plants
Concord Combustion Turbines	Watertown, WI	Natural Gas/Oil	4	352
Germantown Combustion Turbines	Germantown, WI	Natural Gas/Oil	5	258
Paris Combustion Turbines	Union Grove, WI	Natural Gas/Oil	4	352
Port Washington Generating Station	Port Washington, WI	Natural Gas	2	1,082
Valley Power Plant	Milwaukee, WI	Natural Gas	2	240
Total natural gas-fired plants			17	2,284
Renewables
Hydro Plants (13 in number)	WI	Hydro	33	86
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			234	187
Total system			267	6,060


⁽¹⁾	Based on expected capacity ratings for summer 2016, 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⁾	We expect to complete the sale of the MCPP during the first half of 2016.


⁽³⁾	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.

As of December 31, 2015, we operated approximately 21,500 pole-miles of overhead distribution lines and 24,400 miles of underground distribution cable, as well as 366 distribution substations and approximately 298,900 line transformers.

As of December 31, 2015, our natural gas distribution system included approximately 9,700 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 407,000 natural gas lateral services. We have a liquefied natural gas storage plant that converts and stores, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plant has a send-out capability of 70,000 Dth per day. Our natural gas distribution system consists almost entirely of plastic and coated steel pipe.

We also own office buildings, natural gas regulating and metering stations, and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services and natural gas distribution mains and



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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, 2015, the combined steam systems supplied by the VAPP and Milwaukee County Power Plant consisted of approximately 42 miles of both high pressure and low pressure steam piping, nine miles of walkable tunnels and other pressure regulating equipment.

ITEM 3. LEGAL PROCEEDINGS

In addition to those legal proceedings discussed in this Annual Report on Form 10-K, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these other legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

See Note 15, Commitments and Contingencies, and Note 19, Regulatory Environment, for more 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, 2015 are listed below along with their business experience during the past five years. All officers are appointed until they resign, die, or are removed pursuant to 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.

Gale E. Klappa. Age 65.


•	WEC Energy Group — Director since 2003. Chairman and Chief Executive Officer since May 2004. President from April 2003 to July 2013.


•	Wisconsin Electric — Director since 2003. Chairman of the Board since May 2004. Chief Executive Officer since August 2003. President from August 2003 to June 2015.


•	Director of Joy Global, Inc. since 2006 and Badger Meter, Inc. since 2010.

J. Kevin Fletcher. Age 57.


•	Wisconsin Electric — Director and Executive Vice President - Customer Service and Operations since June 2015. Senior Vice President - Customer Operations from October 2011 to June 2015.


•	Georgia Power — Vice President - Community and Economic Development from 2007 to October 2011. Georgia Power is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.

Robert M. Garvin. Age 49.


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


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


•	ATC — Vice President and General Counsel from 2009 to April 2011.

William J. Guc. Age 46.


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


•	Wisconsin Electric — Vice President and Controller since October 2015.


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

J. Patrick Keyes. Age 50.


•	WEC Energy Group — Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.


•	Wisconsin Electric — Director since June 2015. Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.


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

Scott J. Lauber. Age 50.


•	WEC Energy Group — Vice President and Treasurer since February 2013. Assistant Treasurer from March 2011 to January 2013.


•	Wisconsin Electric — Vice President and Treasurer since February 2013. Assistant Treasurer from March 2011 to January 2013.

Allen L. Leverett. Age 49.


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


•	Wisconsin Electric — Director and President since June 2015. Executive Vice President from May 2004 to June 2015. Chief Financial Officer from July 2003 to February 2011.

Susan H. Martin. Age 63.


•	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.


•	Wisconsin Electric — 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.



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Joan M. Shafer. Age 62.


•	Wisconsin Electric — 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.

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

Certain executive officers also hold 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. Dividends were paid to our sole common stockholder, WEC Energy Group. There is no established public trading market for our common stock.



Quarter
(in millions)	2015		2014
First	$	60.0	$	110.0
Second	60.0		110.0
Third	60.0		110.0
Fourth	60.0		60.0
Total	$	240.0	$	390.0

Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the 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 9, 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)	2015		2014		2013		2012		2011
Operating revenues	$	3,854.1	$	4,059.4	$	3,800.2	$	3,613.3	$	3,727.6
Net income attributed to common shareholder	375.7		376.7		360.0		366.1		338.4
Total assets ^{(1) (2)}	13,139.6		12,597.2		12,207.2		12,016.2		11,659.3
Long-term debt and capital lease obligations (excluding current portion) ⁽¹⁾	5,351.3		4,875.2		4,876.7		4,917.5		4,982.1


⁽¹⁾	In the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs previously reported as other long-term assets were reclassified to offset long-term debt for all periods presented. Amounts reclassified were $2.8 million in 2014, $2.6 million in 2013, $2.3 million in 2012, and $2.0 million in 2011.

⁽²⁾

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



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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 are primarily engaged in the business of generating and distributing electricity in Wisconsin and the Upper Peninsula of Michigan, and distributing natural gas in Wisconsin. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies." We conduct our business primarily in three reportable segments, an electric utility segment, a natural gas utility segment, and a steam utility segment. See Note 21, Segment Information, for more information on our reportable business segments.

Corporate Strategy

Our goal is to create long-term value for WEC Energy Group's stockholders and our customers 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 network.

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

Operating Efficiency

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


•	VAPP is a co-generation plant in Milwaukee that was constructed in 1968. The plant originally utilized coal to produce electricity and steam; however, the plant's fuel source was converted to natural gas with construction completed in November 2015. Changing the fuel source is expected to reduce operating costs and enhance environmental performance without decreasing the plant’s capacity.

•

We received approval from the PSCW to make changes at the Oak Creek Expansion units to enable them to burn coal from the Powder River Basin (PRB) in the Western United States. The coal plant was originally designed to burn coal mined from the Eastern United States, but the price of that coal increased relative to the PRB coal in recent years. This project is expected to create flexibility and enable 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.

Financial Discipline

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

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

Exceptional Customer Care

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



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RESULTS OF OPERATIONS

Consolidated Earnings

The following table compares our consolidated results:



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

Electric Utility Segment Contribution to Operating Income

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



	Year Ended December 31
(in millions)	2015		2014		2013
Electric revenues	$	3,413.4	$	3,401.1	$	3,308.7
Fuel and purchased power	1,141.4		1,214.0		1,144.5
Total electric margins	2,272.0		2,187.1		2,164.2

Other operation and maintenance	1,309.1		1,268.9		1,323.8
Depreciation and amortization	270.4		244.1		201.5
Property and revenue taxes	109.8		108.5		105.7
Operating income	$	582.7	$	565.6	$	533.2

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



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


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



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


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

2015 Compared with 2014

Operating Income

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


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


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

•

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


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


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


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


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

These increases in operating income were partially offset by:


•	A $40.2 million increase in other operation and maintenance expense, driven by:


◦	A $48.6 million increase from higher PTF lease expense and associated operating and maintenance expenses as approved in our PSCW rate order, effective January 1, 2015.


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


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



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


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


▪	Other decreases in other operation and maintenance expenses that were not individually significant.


•	A $26.3 million increase in other depreciation and amortization expense, driven by:


◦	An overall increase in utility plant in service in 2015. During 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 a Treasury Grant associated with the completion of our biomass plant in 2013. The lower grant income corresponds to lower bill credits provided to our retail electric customers in Wisconsin.

2014 Compared with 2013

Operating Income

Operating income at the electric utility segment increased $32.4 million, driven by:


•	A $120.9 million increase in sales for resale in 2014 due to higher sales into the MISO Energy Markets as a result of Michigan's alternative electric supplier program and increased availability of our generating units. The margins on these sales are used to reduce fuel costs for our retail customers.


•	A $59.4 million increase in other operating revenues in 2014, primarily driven by the recognition of $56.4 million related to revenues under the SSR agreement with MISO. See Note 20, Michigan Settlement, for more information.


•	A $54.9 million decrease in other operation and maintenance expense in 2014. This decrease was primarily driven by lower benefit costs related to pension, postretirement, and medical costs. Our operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages, and amortization of regulatory assets.


•	A $38.3 million increase in Wisconsin net retail pricing in 2014, primarily related to our PSCW rate order, effective January 1, 2013.

These increases in operating income were partially offset by:


•	A $78.4 million decrease in large commercial and industrial sales in 2014 due to the two iron ore mines switching to an alternative electric supplier in September 2013.


•	A $69.5 million increase in electric fuel and purchased power costs in 2014. This increase was primarily driven by a 1.5% increase in total MWh sales and higher generating costs due to an increase in natural gas prices.

•

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


•	A $45.8 million decrease in electric revenues related to unseasonably cool summer weather in 2014. As measured by cooling degree days, 2014 was 36.6% cooler than normal and 32.6% cooler than 2013 due to mild second and third quarters. The unfavorable impact of the cool summer weather was partially offset by the cold winter weather.



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◦	Residential sales decreased 2.4%, primarily due to the weather.


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

Natural Gas Utility Segment Contribution to Operating Income

Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold decreased 32.4% in 2015 and increased 44.7% in 2014, neither of which had an impact on margins.



	Year Ended December 31
(in millions)	2015		2014		2013
Natural gas revenues	399.7		614.2		451.9
Cost of natural gas sold	244.6		432.6		278.3
Total natural gas margins	155.1		181.6		173.6

Other operation and maintenance	59.2		70.0		75.0
Depreciation and amortization	29.1		30.5		25.5
Property and revenue taxes	6.2		3.9		3.3
Operating income	$	60.6	$	77.2	$	69.8

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



	Year Ended December 31
	Therms (in millions)
Natural Gas Sales Volumes	2015	2014	2013
Customer class
Residential	341.2	399.3	380.8
Commercial and industrial	194.5	240.4	215.7
Other	0.6	0.7	0.6
Total retail	536.3	640.4	597.1
Transport	342.8	343.1	327.6
Total sales in therms	879.1	983.5	924.7



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


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

2015 Compared with 2014

Operating Income

Operating income at the natural gas utility segment decreased $16.6 million, driven by:


•	A $26.5 million decrease in natural gas margins in 2015 resulting from:


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



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◦	A $10.7 million decrease in margins as a result of the impact of the PSCW rate order, effective January 1, 2015. See Note 19, Regulatory Environment, for more information.

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

2014 Compared with 2013

Operating Income

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


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


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

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

Steam Utility Segment Contribution to Operating Income

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



	Year Ended December 31
(in millions)	2015		2014		2013
Steam revenues	$	41.0	$	44.1	$	39.6
Fuel costs	13.0		14.1		13.6
Total steam margins	28.0		30.0		26.0

Other operation and maintenance	16.6		17.5		18.5
Depreciation and amortization	4.5		3.7		3.6
Property and revenue taxes	1.3		1.2		1.0
Operating income	$	5.6	$	7.6	$	2.9



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

2015 Compared with 2014

Operating Income

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



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2014 Compared with 2013

Operating Income

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

Equity in Earnings of Transmission Affiliate



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

2015 Compared with 2014

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

2014 Compared with 2013

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

Consolidated Other Income, Net



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

2015 Compared with 2014

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

2014 Compared with 2013

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

Consolidated Interest Expense



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

2015 Compared with 2014

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



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2014 Compared with 2013

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

Income Tax Expense



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

2015 Compared with 2014

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

2014 Compared with 2013

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

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during 2015, 2014, and 2013:



(in millions)	2015			2014			2013			Change in 2015 Over 2014			Change in 2014 Over 2013
Cash provided by (used in)
Operating activities	$	674.4		$	862.8		$	862.6		$	(188.4	)	$	0.2
Investing activities	(520.2		)	(567.5		)	(560.1		)	47.3			(7.4		)
Financing activities	(151.1		)	(296.4		)	(311.5		)	145.3			15.1

Operating Activities

2015 Compared with 2014

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


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


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


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

2014 Compared with 2013

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



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Investing Activities

2015 Compared with 2014

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

2014 Compared with 2013

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

Capital Expenditures

Capital expenditures by business segment for the year ended December 31 were as follows:



Reportable Segment (in millions)	2015		2014		2013		Change in 2015 Over 2014			Change in 2014 Over 2013
Electric utility	$	444.6	$	489.3	$	467.8	$	(44.7	)	$	21.5
Natural gas utility	71.7		69.3		60.0		2.4			9.3
Steam utility	2.9		3.2		11.1		(0.3		)	(7.9		)
WEPCO consolidated	$	519.2	$	561.8	$	538.9	$	(42.6	)	$	22.9

See Capital Expenditures and Significant Projects below for more information.

Financing Activities

2015 Compared with 2014

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


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


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


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

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

2014 Compared with 2013

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

Significant Financing Activities

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

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



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Capital Resources and 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 11, Short-Term Debt and Lines of Credit, for more information about our credit facility and other short-term credit agreements.

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



(in millions)	2015				2014
Common equity	$	3,564.0	38.6	%	$	3,412.8	37.9	%
Preferred stock	30.4		0.3	%	30.4		0.3	%
Long-term debt	2,658.8		28.8	%	2,412.7		26.8	%
Capital lease obligations ⁽¹⁾	2,816.1		30.5	%	2,818.1		31.3	%
Short-term debt ⁽²⁾	163.6		1.8	%	329.2		3.7	%
Total	$	9,232.9	100.0	%	$	9,003.2	100.0	%


⁽¹⁾	Includes current maturities.


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

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

At December 31, 2015, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 11, Short-Term Debt and Lines of Credit, for more information on our credit facility and other short-term credit agreements. See Note 12, Long-Term Debt and Capital Lease Obligations, for more information on our long-term debt.



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Capital Requirements

Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2015:



	Payments Due by Period ⁽¹⁾
(in millions)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt obligations ⁽²⁾	$	5,104.2	$	115.9	$	477.8	$	460.8	$	4,049.7
Capital lease obligations ⁽³⁾	9,422.5		459.5		858.2		861.5		7,243.3
Operating lease obligations ⁽⁴⁾	37.8		4.9		7.1		2.7		23.1
Energy and transportation purchase obligations ⁽⁵⁾	10,775.5		713.4		1,168.5		1,000.0		7,893.6
Purchase orders ⁽⁶⁾	103.5		44.2		31.7		17.6		10.0
Pension and OPEB funding obligations ⁽⁷⁾	20.5		6.7		13.8		—		—
Capital contributions to equity method investments	3.4		3.4		—		—		—
Total contractual obligations	$	25,467.4	$	1,348.0	$	2,557.1	$	2,342.6	$	19,219.7


⁽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 PTF leases.


⁽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 2018.

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 13, Income Taxes.

AROs in the amount of $58.7 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.

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

Capital Expenditures and Significant Capital Projects

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



(in millions)
2016	$	495.7
2017	532.3
2018	608.9
Total	$	1,636.9

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



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

Common Stock Matters

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

Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $1.4 billion as of December 31, 2015. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $107.6 million, $10.4 million, and $17.6 million to our pension and OPEB plans in 2015, 2014, and 2013, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 14, Employee Benefits.

Off-Balance Sheet Arrangements

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

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

Market Risks and Other Significant Risks

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

Regulatory Recovery

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 authorities. Our primary regulator is the PSCW. See Note 19, Regulatory Environment, for additional information regarding recent rate proceedings and orders.

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. In general, our regulatory assets are recovered in a period between one to 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, 2015, our regulatory assets totaled $1,855.9 million and our regulatory liabilities totaled $741.2 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 – C. Regulation for more information on these mechanisms.



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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 revenues are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas revenues are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2015, 2014 and 2013, as measured by degree days, may be found above in Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

Interest Rates

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, 2015, and December 31, 2014, a hypothetical increase in market interest rates of one-percentage point would have increased annual interest expense by $1.4 million and $3.1 million, 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.

Marketable Securities Return

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

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



(in millions)	As of December 31, 2015		Expected Return on Assets in 2016
Pension trust funds	$	1,179.3	7.00	%
OPEB trust funds	$	216.1	7.25	%

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

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.



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Economic Conditions

Our service territory is within the state of Wisconsin and the Upper Peninsula of Michigan. 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 Risk Factors in Item 1A.

Industry Restructuring

Electric Utility Industry

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

Restructuring in Wisconsin

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

Restructuring in Michigan

Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. Some of our small retail customers have switched to an alternative electric supplier. The law limits customer choice to 10% of our Michigan retail load, but the two iron ore mines in our service territory are excluded from this cap. See Note 20, Michigan Settlement, for information on the mines' ability to switch to an alternative electric supplier. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

Natural Gas Utility Industry

Restructuring in Wisconsin

The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer classes with workably competitive market choices and has adopted standards for transactions between a utility and its natural gas marketing affiliates. All of our Wisconsin customer classes have workably competitive market choices and, therefore, can purchase natural gas directly from a third party supplier. However, work on deregulation of the natural gas distribution industry by the PSCW continues to be on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.



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Environmental Matters

Cross-State Air Pollution Rule

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

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

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

Other Matters

American Transmission Company Allowed Return On Equity Complaint

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

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

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

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



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

In April 2015, WP&L filed a CPCN application with the PSCW for approval to construct an approximate 650 MW natural gas-fired combined-cycle generating unit in Beloit, Wisconsin. Recent construction proposals received by WP&L indicate that the unit could generate up to 700 MWs. In the third quarter of 2015, we, along with our affiliated utility, Wisconsin Public Service Corporation (WPS), requested and received intervention in this proceeding. As intervenors, we and WPS proposed purchased power agreement alternatives to the new generating unit. In December 2015, we entered into a settlement agreement with WPS and WP&L that was approved by the PSCW. Based on the settlement agreement, the generating unit cannot become commercially operational before June 1, 2020. In addition, WP&L must enter into a purchased power agreement with us for MISO planning years 2017, 2018, and 2019, whereby we will sell and WP&L will purchase capacity and energy at certain agreed upon prices. WPS will have the option to purchase an undivided ownership interest of up to 100 MWs of generating capacity from the unit during the first two years of operation and up to an aggregate 200 MWs of generating capacity during the third and fourth years of operation. Other major terms of the settlement included agreement on ownership of future natural gas units and negotiation of a renewable generation joint development plan.

Bonus Depreciation Provisions

The Protecting Americans from Tax Hikes Act of 2015 was signed into law on December 18, 2015. This act extended 50% bonus depreciation to assets placed in service during 2015 through 2017, 40% bonus depreciation to assets placed in service during 2018, and 30% bonus depreciation to assets placed in service during 2019. Bonus depreciation is an additional amount of deductible depreciation that is awarded above and beyond what would normally be available. Due to the increase in federal tax depreciation for 2014 and prior years, we did not make federal income tax payments for 2014 or 2013.

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 noncontributory defined benefit pension benefits and OPEB, described in Note 14, Employee Benefits, are dependent on numerous factors resulting from actual plan experience and assumptions regarding 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 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 2015 Pension Cost
Discount rate	(0.5)	$	72.4		$	4.6
Discount rate	0.5	(65.6		)	(4.9		)
Rate of return on plan assets	(0.5)	N/A			6.0
Rate of return on plan assets	0.5	N/A			(6.0		)

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



Actuarial Assumption (in millions, except percentages)	Percentage-Point Change in Assumption	Impact on Postretirement Benefit Obligation			Impact on 2015 Postretirement Benefit Cost
Discount rate	(0.5)	$	21.6		$	0.8
Discount rate	0.5	(19.4		)	(0.6		)
Health care cost trend rate	(0.5)	(13.0		)	(1.4		)
Health care cost trend rate	0.5	14.7			1.6
Rate of return on plan assets	(0.5)	N/A			1.1
Rate of return on plan assets	0.5	N/A			(1.1		)

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

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

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

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

Regulatory Accounting

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

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



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

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 2015 of approximately $3.9 billion included accrued revenues of $200.2 million as of December 31, 2015.

Income Tax Expense

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

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in Item 7. of this report, as well as Note 1(o), Derivative Instruments, and Note 1(n), Fair Value Measurements, 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:

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, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 26, 2016



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B. CONSOLIDATED INCOME STATEMENTS



Year Ended December 31
(in millions)	2015			2014			2013
Operating revenues	$	3,854.1		$	4,059.4		$	3,800.2

Operating expenses
Cost of sales	1,399.0			1,660.7			1,436.4
Other operation and maintenance	1,384.9			1,356.4			1,417.3
Depreciation and amortization	304.0			278.3			230.6
Property and revenue taxes	117.3			113.6			110.0
Total operating expenses	3,205.2			3,409.0			3,194.3

Operating income	648.9			650.4			605.9

Equity in earnings of transmission affiliate	47.8			57.9			60.2
Other income, net	11.2			8.7			17.4
Interest expense	119.0			116.5			121.4
Other expense	(60.0		)	(49.9		)	(43.8		)

Income before income taxes	588.9			600.5			562.1
Income tax expense	212.0			222.6			200.9
Net income	376.9			377.9			361.2

Preferred stock dividend requirements	1.2			1.2			1.2
Net income attributed to common shareholder	$	375.7		$	376.7		$	360.0

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



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C. CONSOLIDATED BALANCE SHEETS



At December 31
(in millions, except share and per share amounts)	2015			2014
Assets
Property, plant, and equipment
In service	$	10,917.1		$	10,544.4
Accumulated depreciation	(3,461.9		)	(3,406.1		)
	7,455.2			7,138.3
Construction work in progress	170.6			140.9
Leased facilities, net	2,141.7			2,215.0
Net property, plant, and equipment	9,767.5			9,494.2
Investments
Equity investment in transmission affiliate	382.2			372.9
Other	0.3			0.2
Total investments	382.5			373.1
Current assets
Cash and cash equivalents	27.1			24.0
Accounts receivable and unbilled revenues, net of reserves of $43.0 and $46.8, respectively	461.4			488.4
Accounts receivable from related parties	41.1			8.1
Materials, supplies, and inventories	301.6			320.5
Prepayments	171.8			139.5
Other	19.6			19.0
Total current assets	1,022.6			999.5
Deferred charges and other assets
Regulatory assets	1,855.9			1,626.9
Other	111.1			103.5
Total deferred charges and other assets	1,967.0			1,730.4
Total assets	$	13,139.6		$	12,597.2

Capitalization and liabilities
Capitalization
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	$	332.9		$	332.9
Additional paid in capital	999.7			984.4
Retained earnings	2,231.4			2,095.5
Preferred stock	30.4			30.4
Long-term debt	2,658.8			2,162.7
Capital lease obligations	2,692.5			2,712.5
Total capitalization	8,945.7			8,318.4
Current liabilities
Current portion of long-term debt and capital lease obligations	123.6			355.6
Short-term debt	144.0			306.8
Subsidiary note payable to WEC Energy Group	19.6			22.4
Accounts payable	286.4			287.2
Accounts payable to related parties	95.7			87.8
Accrued payroll and benefits	87.5			87.1
Other	115.7			113.7
Total current liabilities	872.5			1,260.6
Deferred credits and other liabilities
Regulatory liabilities	741.2			615.9
Deferred income taxes	2,110.0			1,917.2
Pension and other postretirement benefit obligations	210.9			254.5
Other	259.3			230.6
Total deferred credits and other liabilities	3,321.4			3,018.2

Commitments and contingencies (Note 15)

Total capitalization and liabilities	$	13,139.6		$	12,597.2

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



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D. CONSOLIDATED STATEMENTS OF CASH FLOWS



Year Ended December 31
(in millions)	2015			2014			2013
Operating activities
Net income	$	376.9		$	377.9		$	361.2
Reconciliation to cash provided by operating activities
Depreciation and amortization	323.7			302.6			285.2
Deferred income taxes and investment tax credits, net	178.9			191.4			193.6
Contributions to pension and OPEB plans	(107.6		)	(10.4		)	(17.6		)
Change in –
Accounts receivable and unbilled revenues	(2.9		)	91.0			(137.0		)
Materials, supplies, and inventories	18.8			(39.5		)	31.2
Other current assets	(2.5		)	(8.7		)	0.7
Accounts payable	(5.9		)	18.2			(29.4		)
Accrued taxes, net	(42.1		)	(7.5		)	23.6
Other current liabilities	(1.2		)	(36.8		)	13.1
Other, net	(61.7		)	(15.4		)	138.0
Net cash provided by operating activities	674.4			862.8			862.6

Investing activities
Capital expenditures	(519.2		)	(561.8		)	(538.9		)
Investment in transmission affiliate	(4.6		)	(11.5		)	(9.2		)
Other, net	3.6			5.8			(12.0		)
Net cash used in investing activities	(520.2		)	(567.5		)	(560.1		)

Financing activities
Dividends paid on common stock	(240.0		)	(390.0		)	(340.0		)
Dividends paid on preferred stock	(1.2		)	(1.2		)	(1.2		)
Issuance of long-term debt	500.0			250.0			250.0
Retirement of long-term debt	(250.0		)	(300.0		)	(300.0		)
Change in total short-term debt	(162.8		)	131.9			68.4
Other, net	2.9			12.9			11.3
Net cash used in financing activities	(151.1		)	(296.4		)	(311.5		)

Net change in cash and cash equivalents	3.1			(1.1		)	(9.0		)
Cash and cash equivalents at beginning of year	24.0			25.1			34.1
Cash and cash equivalents at end of year	$	27.1		$	24.0		$	25.1

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



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E. CONSOLIDATED STATEMENTS OF EQUITY



	Wisconsin Electric Power Company Common Shareholders' Equity
	Common Stock		Additional Paid-In Capital		Retained Earnings			Total Common Shareholders' Equity			Preferred Stock		Total Equity
(in millions)	Common Stock		Additional Paid-In Capital		Retained Earnings			Total Common Shareholders' Equity			Preferred Stock		Total Equity
Balance at December 31, 2012	$	332.9	$	944.7	$	2,088.8		$	3,366.4		$	30.4	$	3,396.8
Net income	—		—		361.2			361.2			—		361.2
Dividends
Common stock	—		—		(340.0		)	(340.0		)	—		(340.0		)
Preferred stock	—		—		(1.2		)	(1.2		)	—		(1.2		)
Stock-based compensation	—		3.7		—			3.7			—		3.7
Tax benefit of exercised stock options allocated from parent	—		16.7		—			16.7			—		16.7
Balance at December 31, 2013	332.9		965.1		2,108.8			3,406.8			30.4		3,437.2
Net income	—		—		377.9			377.9			—		377.9
Dividends
Common stock	—		—		(390.0		)	(390.0		)	—		(390.0		)
Preferred stock	—		—		(1.2		)	(1.2		)	—		(1.2		)
Stock-based compensation	—		3.5		—			3.5			—		3.5
Tax benefit of exercised stock options allocated from parent	—		15.8		—			15.8			—		15.8
Balance at December 31, 2014	332.9		984.4		2,095.5			3,412.8			30.4		3,443.2
Net income	—		—		376.9			376.9			—		376.9
Dividends
Common stock	—		—		(240.0		)	(240.0		)	—		(240.0		)
Preferred stock	—		—		(1.2		)	(1.2		)	—		(1.2		)
Stock-based compensation	—		3.2		—			3.2			—		3.2
Tax benefit of exercised stock options allocated from parent	—		12.1		—			12.1			—		12.1
Other	—		—		0.2			0.2			—		0.2
Balance at December 31, 2015	$	332.9	$	999.7	$	2,231.4		$	3,564.0		$	30.4	$	3,594.4

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



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F. CONSOLIDATED STATEMENTS OF CAPITALIZATION



At December 31 (in millions, except share and per share amounts)			2015			2014
Common equity (See Consolidated Statements of Equity)
Common stock – $10 par value; authorized
65,000,000 shares; outstanding – 33,289,327 shares			$	332.9		$	332.9
Additional paid in capital			999.7			984.4
Retained earnings			2,231.4			2,095.5
Total common equity			3,564.0			3,412.8

Preferred stock			30.4			30.4

Long-term debt	Interest Rate	Year Due
Debentures (unsecured)	6.25%	2015	—			250.0
	1.70%	2018	250.0			250.0
	4.25%	2019	250.0			250.0
	2.95%	2021	300.0			300.0
	3.10%	2025	250.0			—
	6.50%	2028	150.0			150.0
	5.625%	2033	335.0			335.0
	5.70%	2036	300.0			300.0
	3.65%	2042	250.0			250.0
	4.25%	2044	250.0			250.0
	4.30%	2045	250.0			—
	6.875%	2095	100.0			100.0

Note (secured, nonrecourse)	4.81%	2030	2.0			2.0

Obligations under capital leases			2,816.1			2,818.1
Total long-term debt and capital lease obligations			5,503.1			5,255.1
Unamortized debt issuance costs			(3.9		)	(2.8		)
Unamortized discount, net			(24.3		)	(21.5		)
Total			5,474.9			5,230.8
Current portion of long-term debt and capital lease obligations			(123.6		)	(355.6		)
Total long-term debt and capital lease obligations			5,351.3			4,875.2
Total long-term capitalization			$	8,945.7		$	8,318.4

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



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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, Acquisition, for more information on this acquisition.

We are an electric, natural gas, and steam utility company that services electric customers in Wisconsin and Michigan's Upper Peninsula, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin.

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

At December 31, 2015, we had one wholly owned subsidiary, Bostco. Bostco had total assets of $29.8 million and $28.4 million as of December 31, 2015 and 2014, respectively. The financial statements include our accounts and the accounts of our wholly owned subsidiary. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

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

(b) Reclassifications—On the income statements for the years ended December 31, 2014 and 2013, we reclassified $17.4 million and $48.0 million, respectively, from treasury grant to depreciation and amortization. This reclassification was made to be consistent with the current year presentation on the income statements.

During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $2.8 million, previously reported as other long-term assets, were reclassified to offset long-term debt on the December 31, 2014 balance sheet. We also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes, during the fourth quarter of 2015. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $46.7 million, previously reported as a separate component of current assets, to offset long-term deferred income tax liabilities on the December 31, 2014 balance sheet.

On the statements of cash flows for the years ended December 31, 2014 and 2013, we reclassified $0.8 million and $3.1 million, respectively, from depreciation and amortization to other operating activities. In addition, we reclassified $10.4 million and $17.6 million of nonqualified pension and OPEB contributions from other operating activities to contributions to pension and OPEB plans on the statements of cash flows for the years ended December 31, 2014 and 2013, respectively. These reclassifications were made to be consistent with the current year presentation on the statements of cash flows.

(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.

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

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

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


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


•	Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of



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actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater return on common equity than authorized by the PSCW.


•	We received payments from MISO under an SSR agreement for our PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 19, Regulatory Environment, and Note 20, Michigan Settlement, for more information.


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


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

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

We provide regulated electric, natural gas, and steam service to customers in Wisconsin and Michigan's Upper Peninsula. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2015. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2015.

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



(in millions)	2015		2014
Materials and supplies	$	151.1	$	145.0
Fossil fuel	110.5		125.5
Natural gas in storage	40.0		50.0
Total	$	301.6	$	320.5

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

(f) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 6, Regulatory Assets and Liabilities, for more information.

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



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Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.01%, 2.93%, and 2.90% in 2015, 2014, and 2013, respectively.

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

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

Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.45% for 2015 and 9.09% for 2014 and 2013, respectively. Our average AFUDC wholesale rates were 1.72%, 0.87%, and 5.89% for 2015, 2014, and 2013, respectively.

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



(in millions)	2015		2014		2013
AFUDC – Debt	$	2.2	$	1.8	$	7.4
AFUDC – Equity	$	5.7	$	4.4	$	17.6

(i) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. A liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The AROs are accreted to their present value each period using the credit-adjusted risk-free interest rate associated with the expected settlement dates of the AROs. This rate is determined when the obligation is incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 8, Asset Retirement Obligations, for more information.

(j) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 15, Commitments and Contingencies, for more information.

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

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

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

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



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expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 13, Income Taxes, for more information.

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

(l) Employee Benefits—The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 14, Employee Benefits, for more information.

(m) Stock-Based Compensation—Our employees participate in the WEC Energy Group stock-based compensation plans. We record costs allocated to us related to awards held by our employees.

In accordance with stockholder approved plans, WEC Energy Group provides a long-term incentive through its equity interests to its outside directors, selected officers, and other key employees. The plans provide for the granting of stock options, restricted stock awards, performance shares, and other share-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. We recognize share-based compensation expense on a straight-line basis. Accordingly, for employee awards classified as equity awards, share-based compensation expense is measured based on the grant-date fair value of the award and is recognized as expense ratably over the requisite service period.

Stock Options

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

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



	2015			2014			2013
Non-qualified stock options granted	495,550			864,860			1,365,970

Estimated fair value per non-qualified stock option	$	5.29		$	4.18		$	3.45

Risk-free interest rate	0.1% – 2.1%			0.1% – 3.0%			0.1% – 1.9%
Dividend yield	3.7		%	3.8		%	3.7		%
Expected volatility	18.0		%	18.0		%	18.0		%
Expected life (years)	5.8			5.8			5.9
Expected forfeiture rate	2.0		%	2.0		%	2.0		%

The risk-free interest rate is based on the U.S. Treasury interest rate with a term consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate, and expected life assumptions are based on our historical experience.

Restricted Shares

WEC Energy Group restricted shares have a three-year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other WEC Energy Group shareholders.



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Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total stockholder return (stock price appreciation plus dividends) as compared to the total stockholder return of a peer group of companies over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash and are accounted for as liability awards accordingly. We accrue compensation costs over the three-year performance period based on our estimate of the final expected value of the awards.

See Note 9, Common Equity, for more information on WEC Energy Group's share-based compensation plans.

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

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

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

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

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

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

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

We recognize transfers between the levels of the fair value hierarchy as of the end of the reporting period.

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based upon the quoted market value for the same issue, or by using a perpetual dividend discount model. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases, is estimated based upon the quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.

We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.

See Note 16, Fair Value Measurements, for more information.

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



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

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

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 17, Derivative Instruments, for more information.

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

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

NOTE 2—ACQUISITION

On June 29, 2015, our parent company acquired 100% of the outstanding common shares of Integrys, a provider of regulated natural gas and electricity, as well as nonregulated renewable energy and compressed natural gas products and services. The combined company was renamed WEC Energy Group, Inc. Our parent company now owns approximately 60% of ATC, a for-profit transmission company regulated by the FERC. Our ownership interest in ATC did not change as a result of the acquisition.

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

•

We will be subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanism, if we earn over our authorized rate of return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and will reduce our transmission escrow. All utility earnings above the first 50 basis points will be solely used to reduce the transmission escrow.

•

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

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



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In 2015, we recorded $6.6 million of severance expense that resulted from employee reductions related to the post-acquisition integration. This expense is included in the other operation and maintenance line item on the income statement. Severance payments of $1.2 million were made during 2015, leaving a severance accrual of $5.4 million on our balance sheet at December 31, 2015. Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments:



(in millions)	2015
Electric utility segment	$	5.8
Natural gas utility segment	0.7
Steam utility segment	0.1
Total severance expense	$	6.6

NOTE 3—RELATED PARTIES

We and our subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, ATC, and other entities in which we have material interests.

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

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

WBS provides 15 categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBS AIAs, which have been approved, or from which we have been granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the interim WBS AIAs. Other modifications or amendments to the interim WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases.

The PSCW orders approving the Non-WBS AIA and the interim WBS AIAs include an April 1, 2016 sunset date for WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us. We may request one extension of the sunset date. Prior to the sunset date, we, along with WEC Energy Group, will file new or modified Non-WBS and WBS AIAs for approval with the PSCW and other state commissions.

We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost. See Note 4, Investment in American Transmission Company, for more information.

Bostco, our consolidated subsidiary, has a note payable to our parent company, WEC Energy Group. At December 31, 2015 and 2014, the balance of this note payable was $19.6 million and $22.4 million, respectively.



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



(in millions)	2015		2014		2013
Lease agreements
Lease payments to We Power ⁽¹⁾	$	410.5	$	389.0	$	405.8
Construction work in progress billed to We Power	58.8		41.0		21.9
Electric transactions
Purchases from Wisconsin Public Service Corporation	0.1		—		—
Natural gas transactions
Purchases from Wisconsin Gas	5.3		6.6		5.4
Purchases from Wisconsin Public Service Corporation	0.4		—		—
Interest expense ⁽²⁾
WEC Energy Group	1.3		1.5		1.4


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


⁽²⁾	Bostco has a note payable to our parent company, WEC Energy Group.

NOTE 4—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

We own approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC. We have one representative on ATC's ten-member board of directors. Each member of the board has only one vote. Due to voting requirements, no individual board member has more than 10% of the voting control. The following table shows changes to our investment in ATC during the years ended December 31:



(in millions)	2015		2014		2013
Balance at beginning of period	$	372.9	$	354.1	$	332.6
Add: Earnings from equity method investment	47.8		57.9		60.2
Add: Capital contributions	4.6		11.5		9.2
Less: Distributions received	42.9		50.5		47.8
Less: Other	0.2		0.1		0.1
Balance at end of period	$	382.2	$	372.9	$	354.1

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service. The following table summarizes our significant related party transactions with ATC during the years ended December 31:



(in millions)	2015		2014		2013
Charges to ATC for services and construction	$	9.7	$	8.1	$	9.0
Charges from ATC for network transmission services	238.5		231.4		234.2

As of December 31, 2015 and 2014, our balance sheets included the following receivables and payables related to ATC:



(in millions)	2015		2014
Accounts receivable
Services provided to ATC	$	0.6	$	0.6
Accounts payable
Services received from ATC	19.9		19.3



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



(in millions)	2015		2014		2013
Income statement data
Revenues	$	615.8	$	635.0	$	626.3
Operating expenses	319.3		307.4		295.0
Other expense	96.1		88.9		83.7
Net income	$	200.4	$	238.7	$	247.6



(in millions)	December 31, 2015		December 31, 2014
Balance sheet data
Current assets	$	80.5	$	66.4
Noncurrent assets	3,957.6		3,728.7
Total assets	$	4,038.1	$	3,795.1

Current liabilities	$	330.3	$	313.1
Long-term debt	1,800.0		1,701.0
Other noncurrent liabilities	245.0		163.8
Shareholders' equity	1,662.8		1,617.2
Total liabilities and shareholders' equity	$	4,038.1	$	3,795.1

NOTE 5—SUPPLEMENTAL CASH FLOW INFORMATION



(in millions)	2015		2014		2013
Cash paid for interest, net of amount capitalized	$	116.2	$	117.9	$	120.5
Cash paid (received) for income taxes, net of refunds	58.5		20.8		(39.2		)

Significant non-cash transactions:
Construction costs funded through accounts payable	11.7		1.7		4.6

NOTE 6—REGULATORY ASSETS AND LIABILITIES

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



(in millions)	2015		2014		See Note
Regulatory assets ^{(1) (2)}
Plant related – capital leases	$	674.4	$	603.0	12
Unrecognized pension and OPEB costs ⁽³⁾	535.8		498.2		14
Electric transmission costs⁽⁴⁾	191.5		146.0
Income tax related items ⁽⁵⁾	177.4		171.5
SSR	86.1		—		20
Energy efficiency programs ⁽⁶⁾	50.7		62.2
PTF⁽⁷⁾	45.4		66.6
AROs	36.3		17.6		8
Other, net	58.3		61.8
Total regulatory assets	$	1,855.9	$	1,626.9


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


⁽²⁾	As of December 31, 2015, we had $11.3 million of regulatory assets not earning a return and $136.6 million of regulatory assets earning a return based on short-term interest rates.


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



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⁽⁴⁾	Represents amounts recoverable from customers related to transmission costs incurred that exceed amounts authorized for recovery in our current rates.


⁽⁵⁾	Adjustments related to deferred income taxes. As the related temporary differences reverse, we prospectively collect taxes from customers for which deferred taxes were recorded in prior years.


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


⁽⁷⁾	Represents amounts recoverable from customers related to our costs of the PTF units, including subsequent capital additions.

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



(in millions)	2015		2014
Regulatory liabilities
Removal costs⁽¹⁾	$	696.9	$	571.2
Mines deferral ⁽²⁾	31.6		—
Other, net	12.7		44.7
Total regulatory liabilities	$	741.2	$	615.9


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


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

NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

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



(in millions)	2015		2014
Electric utility	$	9,305.9	$	9,024.8
Natural gas utility	1,089.6		1,025.4
Steam utility	104.1		101.5
Common utility	363.5		339.6
Total utility property, plant, and equipment	10,863.1		10,491.3
Less: Accumulated depreciation	3,447.2		3,392.4
Net	7,415.9		7,098.9
Construction work in progress	170.3		140.9
Net utility property, plant, and equipment	7,586.2		7,239.8

Property under capital leases	2,876.7		2,848.6
Less: Accumulated amortization	735.0		633.6
Net leased facilities	2,141.7		2,215.0

Non-utility and other property, plant, and equipment	54.0		53.1
Less: Accumulated depreciation	14.7		13.7
Net	39.3		39.4
Construction work in progress	0.3		—
Net non-utility and other property, plant, and equipment	39.6		39.4

Total property, plant, and equipment	$	9,767.5	$	9,494.2



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NOTE 8—ASSET RETIREMENT OBLIGATIONS

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

The following table shows changes to our AROs:



(in millions)	2015			2014			2013
Balance as of January 1	$	40.5		$	39.4		$	41.5
Accretion	2.3			2.2			2.2
Additions	15.9		*	—			—
Liabilities settled	—			(1.1		)	(4.3		)
Balance as of December 31	$	58.7		$	40.5		$	39.4


*	An ARO was recorded during 2015 for the fly-ash landfills located at our generation facilities.

NOTE 9—COMMON EQUITY

Share-Based Compensation Plans

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



(in millions)	2015		2014		2013
Stock options	$	3.2	$	3.6	$	3.8
Restricted stock	2.1		2.1		1.6
Performance units	7.5		12.7		11.9
Share-based compensation expense	$	12.8	$	18.4	$	17.3
Related tax benefit	$	5.1	$	7.4	$	6.9

Stock-based compensation capitalized was not significant during 2015, 2014, and 2013.

Stock Options

The following is a summary of our employees' WEC Energy Group stock option activity during 2015:



	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding as of January 1, 2015	6,450,277		$	30.07
Granted	495,550		$	52.90
Exercised	(1,258,113	)	$	23.19
Outstanding as of December 31, 2015	5,687,714		$	33.58	5.7	$	101.6
Exercisable as of December 31, 2015	3,087,219		$	26.90	4.0	$	75.4

The intrinsic value of WEC Energy Group options exercised during the years ended December 31, 2015, 2014, and 2013 was

$34.6 million, $47.5 million, and $41.2 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $29.2 million, $47.9 million, and $45.5 million during the years ended December 31, 2015, 2014, and 2013, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $14.0 million, $18.8 million, and $16.6 million, respectively.

As of December 31, 2015, total compensation costs not yet recognized related to non-vested WEC Energy Group stock options held by our employees was approximately $1.5 million, which is expected to be recognized over the next 19 months on a weighted-average basis.



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During the first quarter of 2016, the Compensation Committee awarded 94,740 non-qualified stock options with an exercise price of $50.93 to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restricted Shares

The following activity related to WEC Energy Group restricted stock held by our employees occurred during 2015:



	Number of Shares		Weighted-Average Grant Date Fair Value
Outstanding as of January 1, 2015	100,657		$	38.81
Granted	126,155		$	50.75
Released	(50,230	)	$	37.73
Forfeited	(1,139	)	$	46.26
Outstanding as of December 31, 2015	175,443		$	47.66

On July 31, 2015, the Compensation Committee awarded certain of our officers and other employees an aggregate of 82,943 shares of WEC Energy Group restricted stock for the key role each played in WEC Energy Group's acquisition of Integrys. The restricted stock vests in three equal installments on January 29, 2016, January 31, 2017, and July 31, 2018.

The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $2.7 million, $2.3 million, and

$2.8 million for the years ended December 31, 2015, 2014, and 2013, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $1.1 million, $0.9 million, and $1.1 million, respectively.

As of December 31, 2015, total compensation cost not yet recognized related to our share of WEC Energy Group restricted stock was approximately $2.2 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

During the first quarter of 2016, the Compensation Committee awarded 8,211 restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Performance Units

In January 2015, 2014, and 2013, the Compensation Committee awarded 187,450; 224,735; and 230,245 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan. Performance units earned as of December 31, 2015, 2014, and 2013 vested and were settled during the first quarter of 2016, 2015, and 2014, and had a total intrinsic value of $13.0 million, $11.6 million, and $13.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $4.4 million, $4.2 million, and $4.7 million, respectively. As of December 31, 2015, total compensation cost related to performance units not yet recognized was approximately $11.8 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

During the first quarter of 2016, the Compensation Committee awarded 35,700 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Restrictions

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

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

We may not pay common dividends to WEC Energy Group under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to



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declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.

See Note 11, Short-Term Debt and Lines of Credit for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2015, restricted retained earnings totaled $1.9 billion. Our equity in undistributed earnings of investees accounted for by the equity method was $125.0 million at December 31, 2015.

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

NOTE 10—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2015 and 2014:



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

NOTE 11—SHORT-TERM DEBT AND LINES OF CREDIT

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



	2015			2014
(in millions, except percentages)	Balance			Balance
Commercial paper
Amount outstanding at December 31	$	144.0		$	306.8
Average interest rate on amounts outstanding at December 31	0.70		%	0.25		%
Average amounts outstanding during the year *	159.2			179.5


*	Based on daily outstanding balances during the year.

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

As of December 31, 2015, we had approximately $338.0 million of available capacity under our bank back-up credit facility and $144.0 million of commercial paper outstanding that was supported by the credit facility. As of December 31, 2015, our subsidiary had a $19.6 million note payable to WEC Energy Group with a weighted-average interest rate of 5.15%.

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



(in millions)	Maturity	2015
Revolving credit facility	December 2020	500.0
Total short-term credit capacity		$	500.0

Less:
Letters of credit issued inside credit facility		$	18.0
Commercial paper outstanding		144.0

Available capacity under existing agreement		$	338.0



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In December 2015, we amended our credit facility to extend its expiration to December 2020. The facility has a renewal provision for two one-year extensions, subject to lender approval.

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

NOTE 12—LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

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

In May 2015, we issued $250.0 million of 3.10% Debentures due June 1, 2025. The net proceeds were used to repay short-term debt and for general corporate purposes.

In November 2015, we issued $250.0 million of 4.30% Debentures due December 15, 2045. The proceeds were used to repay short-term debt, to repay a portion of our $250.0 million of 6.25% Debentures that matured on December 1, 2015, and for working capital and other corporate purposes.

Debentures and Notes

As of December 31, 2015, the maturities of our long-term debt outstanding (excluding obligations under capital leases) were as follows:



(in millions)
2016	$	—
2017	—
2018	250.0
2019	250.0
2020	—
Thereafter	2,187.0
Total	$	2,687.0

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

We are the obligor under two series of tax-exempt pollution control refunding bonds in an outstanding principal amount of $147.0 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2015 and 2014, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt or included in our capitalization statements because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Obligations Under Capital Lease

We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under capital lease accounting, we have recorded the leased plants and corresponding obligations under the capital leases on our balance sheets. We treat these agreements as operating leases for rate-making purposes. We record our minimum lease payments under the power purchase contract as purchased power expense on our income statements. We record the lease payments under our PTF leases as rent expense in other operation and maintenance in our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. See Note 6, Regulatory Assets and Liabilities, for more information on our plant related capital leases.



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Power Purchase Commitment

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

PWGS

We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. The leased plants and corresponding obligations for the plants have been recorded at the estimated fair value of $692.5 million. We are amortizing the leased plants on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.4 million in the year 2021 for PWGS 1 and to approximately $130.1 million in the year 2024 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for the plants was $636.5 million as of December 31, 2015, and will decrease to zero over the remaining lives of the contracts.

Oak Creek Expansion

We are leasing OC 1, OC 2 and the common facilities, which are also utilized by our Oak Creek Units 5-8, from We Power under PSCW approved leases. We are amortizing the leased plants on a straight-line basis over the 30-year term of the leases. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively. The leased plants and corresponding capital lease obligations have been recorded at the estimated fair value of $2,043.9 million. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $541.3 million in the year 2029 for OC 1 and to approximately $445.3 million in the year 2030 for OC2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases was $2,119.7 million as of December 31, 2015, and will decrease to zero over the remaining lives of the contracts.

We paid the following lease payments during 2015, 2014, and 2013:



(in millions)	2015		2014		2013
Long-term power purchase commitment	$	36.2	$	34.9	$	33.7
PWGS	103.8		99.2		99.1
Oak Creek expansion	306.7		277.8		274.9
Total	$	446.7	$	411.9	$	407.7



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



(in millions)	2015			2014
Long-term power purchase commitment
Under capital lease	$	140.3		$	140.3
Accumulated amortization	(103.9		)	(98.3		)
Total long-term power purchase commitment	$	36.4		$	42.0

PWGS
Under capital lease	$	692.5		$	682.7
Accumulated amortization	(245.7		)	(217.6		)
Total PWGS	$	446.8		$	465.1

Oak Creek expansion
Under capital lease	$	2,043.9		$	2,025.6
Accumulated amortization	(385.4		)	(317.7		)
Total Oak Creek	$	1,658.5		$	1,707.9

Total leased facilities	$	2,141.7		$	2,215.0

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2015 are as follows:



(in millions)	Power Purchase Commitment			PWGS			Oak Creek Expansion			Total
2016	$	45.1		$	100.8		$	313.6		$	459.5
2017	13.9			100.8			314.0			428.7
2018	14.7			100.8			314.0			429.5
2019	15.5			100.8			314.0			430.3
2020	16.4			100.8			314.0			431.2
Thereafter	24.9			1,101.5			6,116.9			7,243.3
Total minimum lease payments	130.5			1,605.5			7,686.5			9,422.5
Less: Estimated executory costs	(47.4		)	—			—			(47.4		)
Net minimum lease payments	83.1			1,605.5			7,686.5			9,375.1
Less: Interest	(23.2		)	(969.0		)	(5,566.8		)	(6,559.0		)
Present value of net
Minimum lease payments	59.9			636.5			2,119.7			2,816.1
Less: Due currently	(30.3		)	(11.8		)	(81.5		)	(123.6		)
Long-term obligations under capital lease	$	29.6		$	624.7		$	2,038.2		$	2,692.5

NOTE 13—INCOME TAXES

Income Tax Expense

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



(in millions)	2015			2014			2013
Current tax expense	$	33.1		$	31.2		$	7.3
Deferred income taxes, net	180.0			192.5			194.7
Investment tax credit, net	(1.1		)	(1.1		)	(1.1		)
Total income tax expense	$	212.0		$	222.6		$	200.9



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Statutory Rate Reconciliation

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



	2015					2014					2013
(in millions)	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
Expected tax at statutory federal tax rates	$	205.7		35.0	%	$	209.8		35.0	%	$	196.3		35.0	%
State income taxes net of federal tax benefit	31.0			5.3	%	33.0			5.5	%	31.7			5.6	%
Production tax credits	(17.8		)	(3.0	)%	(17.4		)	(2.9	)%	(16.7		)	(3.0	)%
Domestic production activities deduction	(7.8		)	(1.3	)%	—			—	%	—			—	%
AFUDC – Equity	(2.0		)	(0.3	)%	(1.5		)	(0.2	)%	(6.1		)	(1.1	)%
Treasury grant	(1.7		)	(0.3	)%	(3.8		)	(0.6	)%	(7.4		)	(1.3	)%
Investment tax credit restored	(1.1		)	(0.2	)%	(1.1		)	(0.2	)%	(1.1		)	(0.2	)%
Other, net	5.7			0.8	%	3.6			0.5	%	4.2			0.7	%
Total income tax expense	$	212.0		36.0	%	$	222.6		37.1	%	$	200.9		35.7	%

Deferred Income Tax Assets and Liabilities

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



(in millions)	2015		2014
Deferred tax assets
Deferred revenues	$	219.9	$	221.3
Employee benefits and compensation	103.2		103.8
Future federal tax benefits	72.9		56.0
Construction advances	17.7		15.5
Uncollectible account expense	14.3		15.6
Emission allowances	0.2		0.1
Other	48.7		35.0
Total deferred tax assets	476.9		447.3

Deferred tax liabilities
Property-related	2,058.5		1,942.1
Investment in transmission affiliate	174.9		164.1
Employee benefits and compensation	164.6		131.2
Deferred transmission costs	76.7		58.5
Prepaid tax, insurance, and other	50.6		50.5
Other	61.6		18.1
Total deferred tax liabilities	2,586.9		2,364.5
Deferred tax liability, net	$	2,110.0	$	1,917.2

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

As of December 31, 2015, we had approximately $72.9 million of deferred tax assets associated with tax credit carryforwards. As of December 31, 2014, we had approximately $3.9 million and $54.6 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of approximately $1.4 million and $54.6 million, respectively. These tax credit carryforwards begin to expire in 2031. We anticipate having future taxable income sufficient to utilize these deferred tax assets.



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Unrecognized Tax Benefits

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



(in millions)	2015			2014
Balance as of January 1	$	7.2		$	8.4
Reductions for tax positions of prior years	(1.1		)	(1.2		)
Balance as of December 31	$	6.1		$	7.2

The amount of unrecognized tax benefits as of December 31, 2015 and 2014, excludes deferred tax assets related to uncertainty in income taxes of $6.1 million and $7.2 million, respectively. As of December 31, 2015 and 2014, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the year ended December 31, 2015, we recognized approximately $0.1 million of interest income in our income statements. For the years ended December 31, 2014 and 2013, we recognized approximately $0.3 million and $0.2 million, respectively, of interest expense in our income statements. For the years ended December 31, 2015, 2014, and 2013, we recognized no penalties in our income statements. We had approximately $0.6 million and $0.7 million of interest accrued on our balance sheets as of December 31, 2015 and 2014, respectively.

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

Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2012 through 2015 are subject to Federal examination, and the tax years 2011 through 2015 are subject to examination by the state of Wisconsin.

NOTE 14—EMPLOYEE BENEFITS

Pension and Other Postretirement Employee Benefits

We participate in WEC Energy Group's defined benefit pension plans that cover substantially all of our employees. In addition, we participate in WEC Energy Group's OPEB plans that cover substantially all of our employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

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

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

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



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



	Pension Costs						OPEB Costs
(in millions)	2015			2014			2015			2014
Change in benefit obligation
Obligation at January 1	$	1,315.2		$	1,223.1		$	322.3		$	292.4
Service cost	14.7			9.4			9.0			8.1
Interest cost	52.9			59.3			13.4			14.4
Participant contributions	—			—			8.8			8.4
Plan amendments	—			—			—			(5.2		)
Transfer to affiliates	(2.4		)	—			—			—
Actuarial loss (gain)	(11.5		)	110.8			(22.3		)	24.3
Other accrued benefits	—			(0.1		)	—			—
Benefit payments	(78.3		)	(87.3		)	(18.7		)	(21.1		)
Federal subsidy on benefits paid	N/A			N/A			1.3			1.0
Obligation at December 31	$	1,290.6		$	1,315.2		$	313.8		$	322.3

Change in fair value of plan assets
Fair value at January 1	$	1,160.0		$	1,168.9		$	224.9		$	222.4
Actual return on plan assets	(7.8		)	71.2			(1.5		)	12.0
Employer contributions	105.0			7.2			2.6			3.2
Participant contributions	—			—			8.8			8.4
Transfer to affiliates	0.4			—			—			—
Benefit payments	(78.3		)	(87.3		)	(18.7		)	(21.1		)
Fair value at December 31	$	1,179.3		$	1,160.0		$	216.1		$	224.9

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



	Pension Costs				OPEB Costs
(in millions)	2015		2014		2015		2014
Other long-term assets	$	—	$	—	$	1.9	$	1.9
Pension and other postretirement benefit obligations	111.3		155.2		99.6		99.3
Total net liabilities	$	111.3	$	155.2	$	97.7	$	97.4

The accumulated benefit obligation for all defined benefit plans was $1,287.5 million and $1,314.3 million as of December 31, 2015 and 2014, respectively.

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



	Pension Costs				OPEB Costs
(in millions)	2015		2014		2015			2014
Net regulatory assets
Net actuarial loss	$	520.9	$	476.4	$	14.7		$	20.7
Prior service cost (credit)	4.3		6.3		(4.1		)	(5.2		)
Total	$	525.2	$	482.7	$	10.6		$	15.5

We estimate that 2016 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs (credits) referred to above of $33.8 million and $(0.1) million, respectively.



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The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:



	Pension Costs									OPEB Costs
(in millions)	2015			2014			2013			2015			2014			2013
Service cost	$	14.7		$	9.4		$	13.9		$	9.0		$	8.1		$	9.5
Interest cost	52.9			59.3			52.4			13.4			14.4			12.7
Expected return on plan assets	(83.6		)	(79.1		)	(77.2		)	(16.0		)	(16.2		)	(14.5		)
Amortization of prior service cost (credit)	2.0			2.0			2.2			(1.1		)	(1.7		)	(1.9		)
Amortization of net actuarial loss	35.6			26.9			41.7			1.0			0.2			1.5
Amortization of settlement charge	—			—			1.5			—			—			—
Net periodic benefit cost	$	21.6		$	18.5		$	34.5		$	6.3		$	4.8		$	7.3

Assumptions – Pension and Other Postretirement Benefit Plans

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



	Pension Costs			OPEB Costs
	2015	2014	2013	2015	2014	2013
Weighted-average assumptions used to determine benefit obligations as of Dec. 31
Discount rate	4.45%	4.15%	5.00%	4.45%	4.20%	4.95%
Rate of compensation increase	4.00%	4.00%	4.00%	N/A	N/A	N/A

Weighted-average assumptions used to determine net cost for year ended Dec. 31
Discount rate	4.15%	5.00%	4.10%	4.20%	4.95%	4.15%
Expected return on plan assets	7.00%	7.25%	7.25%	7.25%	7.50%	7.50%
Rate of compensation increase	4.00%	4.00%	4.00%	N/A	N/A	N/A

Assumed health care cost trend rates as of Dec. 31
Health care cost trend rate assumed for next year (Pre 65 / Post 65)				7.5%/7.5%	7.5%/7.5%	7.5%/7.5%
Rate that the cost trend rate gradually adjusts to				5.00%	5.00%	5.00%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)				2021/2021	2021/2021	2021/2021

WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2016, the expected return on assets assumption is 7.00% for the pension plan and 7.25% for the OPEB plan.

Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2015, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:



(in millions)	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	3.2	$	(2.6	)
Effect on the health care component of the accumulated postretirement benefit obligation	30.3		(25.2		)

Plan Assets

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

The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target



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asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

Previously, our pension trust target allocation was 45% equity investments and 55% fixed income investments. A transition to a target asset allocation of 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments began in late 2014. The current OPEB trusts' target asset allocations are 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and U.S. Treasuries.

Pension and OPEB plan investments are recorded at fair value. See Note 1(n), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.

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



	As of December 31, 2015
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	15.5	$	—	$	—	$	15.5	$	2.4	$	—	$	—	$	2.4
Equity securities:
U.S. equity	368.4		—		—		368.4		86.6		—		—		86.6
International equity	97.3		23.9		—		121.2		26.9		1.6		—		28.5
Fixed income securities: *
U.S. bonds	33.8		509.5		—		543.3		2.3		78.0		—		80.3
International bonds	54.7		32.6		—		87.3		10.8		4.5		—		15.3
Private Equity and Real Estate	—		—		43.6		43.6		—		—		3.0		3.0
Total	$	569.7	$	566.0	$	43.6	$	1,179.3	$	129.0	$	84.1	$	3.0	$	216.1


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



	As of December 31, 2014
	Pension Plan Assets								OPEB Assets
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	5.1	$	—	$	—	$	5.1	$	0.9	$	—	$	—	$	0.9
Equity securities:
U.S. equity	404.5		—		—		404.5		98.4		—		—		98.4
International equity	103.3		23.9		—		127.2		28.5		1.7		—		30.2
Fixed income securities: *
U.S. bonds	34.2		481.2		—		515.4		2.4		75.8		—		78.2
International bonds	63.7		34.8		—		98.5		11.8		4.7		—		16.5
Private Equity and Real Estate	—		—		9.3		9.3		—		—		0.7		0.7
Total	$	610.8	$	539.9	$	9.3	$	1,160.0	$	142.0	$	82.2	$	0.7	$	224.9


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



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



	Private Equity and Real Estate
(in millions)	Pension			OPEB
Beginning balance at January 1, 2015	$	9.3		$	0.7
Realized and unrealized gains (losses)	1.4			0.1
Purchases	41.8			2.8
Liquidations	(8.9		)	(0.6		)
Ending balance at December 31, 2015	$	43.6		$	3.0



	Private Equity and Real Estate
(in millions)	Pension		OPEB
Beginning balance at January 1, 2014	$	—	$	—
Purchases	9.3		0.7
Ending balance at December 31, 2014	$	9.3	$	0.7

Cash Flows

We expect to contribute $6.6 million to the pension plans and $0.1 million to OPEB plans in 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

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



(in millions)	Pension Costs		OPEB Costs
2016	$	96.5	$	14.4
2017	96.6		15.6
2018	94.3		16.7
2019	93.5		17.8
2020	91.6		18.6
2021-2025	429.0		101.9

Savings Plans

We sponsor savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $13.0 million during 2015, 2014, and 2013.

NOTE 15—COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

Energy Related Purchased Power Agreements

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



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The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2015.



				Payments Due By Period
(in millions)	Date Contracts Extend Through	Total Amounts Committed		2016		2017		2018		2019		2020		Later Years
Electric utility:
Purchased power	2031	$	95.4	$	29.4	$	25.5	$	19.3	$	5.3	$	3.3	$	12.6
Coal supply and transportation	2018	410.3		212.9		130.9		66.5		—		—		—
Nuclear	2033	10,012.5		412.8		415.3		420.0		445.4		475.1		7,843.9
Natural gas utility supply and transportation	2024	257.3		58.3		47.1		43.9		40.0		30.9		37.1
Total		$	10,775.5	$	713.4	$	618.8	$	549.7	$	490.7	$	509.3	$	7,893.6

Operating Leases

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

Rental expense attributable to operating leases was $6.7 million, $4.8 million, and $4.0 million in 2015, 2014, and 2013, respectively.

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



Year Ending December 31	Payments (in millions)
2016	$	4.9
2017	3.8
2018	3.3
2019	1.4
2020	1.3
Later years	23.1
Total	$	37.8

Environmental Matters

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

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


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


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


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


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


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


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


•	the remediation of former manufactured gas plant sites.



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Air Quality

Sulfur Dioxide National Air Ambient Quality Standards

The EPA issued a revised 1-Hour SO₂ NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard.

The final rule affords state agencies latitude in rule implementation. States have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection) and make attainment designation recommendations. If a state chooses modeling and an area does not show attainment, and sources do not agree to reductions by 2017 to allow attainment, the area would be classified as nonattainment. A plan would need to be developed requiring emission reductions to bring the area back into attainment by 2023. Alternatively, if a state opted out of modeling and instead chose to install air quality monitors, and subsequently monitored nonattainment, then it would face a 2026 compliance date. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.

In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO₂. The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016. SO₂emissions from PIPP are above the emission threshold, which means that the Marquette area requires action earlier than would otherwise be required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. Based upon this modeling, the state of Michigan recommended to the EPA that the Marquette area be designated as attainment. We expect that the EPA will act on this recommendation in 2016.

We believe our fleet overall is well positioned to meet the new regulation.

8-Hour Ozone National Air Ambient Quality Standards

The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule.

Mercury and Other Hazardous Air Pollutants

In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule has been remanded to the EPA to address the Supreme Court decision, but remains in effect while the EPA completes its cost evaluation.

Our compliance plans currently include capital projects for PIPP to achieve the required reductions for MATS. Construction on the addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP is essentially complete and going through final startup and tuning.

In April 2013, we received a one year MATS compliance extension from the MDEQ for PIPP through April 2016.



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Climate Change

In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan as an alternative to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and requires states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would be required to submit final plans by September 2018, either alone or in conjunction with other states. States will be required to meet interim goals over the period from 2022 through 2029, and a final goal in 2030, with the goal of reducing nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources.

Rules for existing, as well as new, modified, and reconstructed generating units became effective in October 2015. A draft Federal Plan and Model Trading Rule were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. The utilities' petition narrowly asks the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO₂equivalent reduction goal by about 10%. The state's petition asks for review of a number of aspects of the final rules, including an adjustment to reflect the Kewaunee Power Station retirement. In January 2016, we submitted comments on the draft Federal Plan and Model Trading Rule. Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency. A stakeholder process began in the middle of January 2016. Michigan plans to submit an interim plan by September 6, 2016, with a request for a two year extension for submittal of a final plan.

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

We are required to report our CO₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2014, we reported aggregated CO₂ equivalent emissions of approximately 23.3 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 25.3 million metric tonnes to the EPA for 2015. The level of CO₂ and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO₂ equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2014, we reported aggregated CO₂ equivalent emissions of approximately 4.4 million metric tonnes to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the data, we estimate that we will report CO₂ equivalent emissions of approximately 3.8 million metric tonnes to the EPA for 2015.



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Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for VAPP Units 1 and 2, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in October 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in September 2016.

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

During 2016-2018, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towers that meet EM BTA requirements) and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived.

Steam Electric Effluent Guidelines

The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will likely require additional biological treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Oak Creek Units 5 and 6, the Pleasant Prairie units, and PIPP Units 5 through 9. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $60 million to $80 million for these biological treatment and bottom ash transport systems.

Valley Power Plant Wisconsin Pollution Discharge Elimination System Permit

The WDNR issued a WPDES permit for VAPP that became effective in January 2013. The permit contained several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements included thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure is complete. An identical modification is planned for VAPP Unit 1 in 2016. We are also currently involved in planning to meet the remaining long-term requirements.



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Land Quality

Coal Combustion Residuals Rule

In April 2015, the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule was entered into the Federal Register. The final rule regulates the disposal of coal combustion residuals as a non-hazardous waste. We do not expect the compliance costs will be significant because we currently have a program of beneficial utilization for most of our coal combustion products. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources.

Coal Combustion Product Landfill Sites

We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required some level of monitoring or remediation. Where we have become aware of these conditions, and where necessary, we have worked to define the nature and extent of the impact, if any, and work has been performed to address these conditions. During 2015, 2014 and 2013, landfill remediation expenses were not material. See Note 8, Asset Retirement Obligations, for more information about obligations related to these sites.

Renewables, Efficiency, and Conservation

Wisconsin Act 141

In 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we are required to increase our renewable energy percentage to 8.27%. To comply with these requirements, we constructed the Blue Sky Green Field wind park, the Glacier Hills wind park, and the Rothschild biomass facility. We also rely on renewable energy purchases to meet our renewable portfolio standard commitments.

We are in compliance with Act 141's 2015 standard and have entered into agreements for renewable energy credits, which should allow us to remain in compliance through 2022. If market conditions are favorable, we may purchase more renewable energy credits. Act 141 assigned responsibility for the administration of energy efficiency, conservation, and renewable programs to the PSCW and/or contracted third parties. The funding required by Act 141 for 2015 was 1.2% of our annual operating revenues.

Michigan Act 295

In 2008, Michigan revised the requirements for renewable energy generation by enacting Act 295. Act 295 requires 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. We are currently in compliance with this requirement. Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

Manufactured Gas Plant Remediation

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

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



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



(in millions)	2015		2014
Regulatory assets	$	16.9	$	18.7
Reserves for future remediation	5.6		6.5

Enforcement and Litigation Matters

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

Paris Generating Station Wisconsin Pollution Discharge Elimination System Permit

In November 2014, the WDNR reissued the WPDES permit for the PSGS. We believed that the WDNR imposed unreasonable permit conditions with respect to temperature monitoring, the control of water treatment additive, and phosphorus discharges. To address these permit conditions, we filed a petition for a contested case hearing with the WDNR in January 2015. On the same day, we also filed a request to be covered by the statewide phosphorus variance to address one of our concerns with the permit. We reached an agreement with the WDNR with respect to the permit conditions for temperature monitoring and for restrictions related to the use of a water treatment additive. In March 2015, the WDNR issued a final WPDES permit with agreed upon modifications, and we withdrew our petition for a contested case hearing. In July 2015, the Milwaukee County Circuit Court entered a stipulation and Order for Judgment between the WDNR and Wisconsin Department of Justice. This order resolves the litigation by allowing us to maintain the ability to apply for and be covered by the statewide phosphorus variance.

Paris Generating Station Units 1 and 4 Construction Permit

In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to PSGS Units 1 and 4, allowing those units to restart after a temporary outage related to a construction permit matter with the WDNR. We received an “after the fact” permit from the WDNR, and the units are now available for service. In October, 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit.

In February 2013, the Sierra Club also filed for a contested case hearing with the WDNR in connection with the administration order issued in this matter, which was granted. However, a hearing has not yet been scheduled.

Valley Power Plant Title V Air Permit

In February 2011, the WDNR renewed VAPP's Title V operating permit for five years. In March 2011, the Sierra Club petitioned the EPA for additional reductions and monitoring for particulate matter and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of this proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

Solvay Coke and Gas Site

In August 2004, we were identified as a potentially responsible party at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company of ours owned a parcel of property that is within the property boundaries of the site. In 2007, we and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. The final remedial investigation report was submitted to the EPA in December 2015, and work will now begin on the feasibility study. Under the Administrative Settlement Agreement, we did not admit to any liability for the site, waive any liability defenses, or commit to perform future site remedial activities. Our share of the costs to perform the required work and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported above.



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NOTE 16—FAIR VALUE MEASUREMENTS

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



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

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



	December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.4	$	1.9	$	—	$	2.3
FTRs	—		—		7.0		7.0
Coal contracts	—		3.3		—		3.3
Total derivative assets	$	0.4	$	5.2	$	7.0	$	12.6

Derivative liabilities
Natural gas contracts	$	6.8	$	0.3	$	—	$	7.1
Coal contracts	—		0.2		—		0.2
Total derivative liabilities	$	6.8	$	0.5	$	—	$	7.3

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 17, Derivative Instruments, for more information.

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



(in millions)	2015			2014			2013
Balance as of January 1	$	7.0		$	3.5		$	4.7
Purchases	3.9			15.6			10.6
Settlements	(9.3		)	(12.1		)	(11.8		)
Balance as of December 31	$	1.6		$	7.0		$	3.5

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



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Fair Value of Financial Instruments

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



	December 31, 2015				December 31, 2014
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	27.3	$	30.4	$	27.1
Long-term debt including current portion *	$	2,658.8	$	2,888.2	$	2,412.7	$	2,759.6


*	Long-term debt excludes capital lease obligations.

NOTE 17—DERIVATIVE INSTRUMENTS

The following table shows our derivative assets and derivative liabilities:



		December 31, 2015				December 31, 2014
(in millions)	Balance Sheet Presentation	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Natural gas	Other current	$	0.5	$	8.1	$	2.3	$	6.4
Natural gas	Other long-term	—		1.3		—		0.7
Petroleum products	Other current	0.9		3.3		—		—
Petroleum products	Other long-term	0.3		1.1		—		—
FTRs	Other current	1.6		—		7.0		—
Coal	Other current	1.7		3.4		2.7		0.2
Coal	Other long-term	0.3		4.2		0.6		—
	Other current	4.7		14.8		12.0		6.6
	Other long-term	0.6		6.6		0.6		0.7
Total		$	5.3	$	21.4	$	12.6	$	7.3

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



	December 31, 2015				December 31, 2014			December 31, 2013
(in millions)	Volume	Gains (Losses)			Volume	Gains		Volume	Gains (Losses)
Natural gas	24.0 Dth	$	(12.6	)	21.4 Dth	$	4.0	24.0 Dth	$	(4.0	)
Petroleum products	4.0 gallons	(0.2		)	9.2 gallons	0.5		8.6 gallons	0.5
FTRs	22.8 MWh	3.2			26.1 MWh	12.7		25.3 MWh	14.9
Total		$	(9.6	)		$	17.2		$	11.4

As of December 31, 2015 and 2014, we posted collateral of $14.9 million and $6.9 million, respectively, in our margin accounts.

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



	December 31, 2015						December 31, 2014
	Derivative			Derivative			Derivative			Derivative
(in millions)	Assets			Liabilities			Assets			Liabilities
Gross amount recognized on the balance sheet	$	5.3		$	21.4		$	12.6		$	7.3
Gross amount not offset on the balance sheet *	(0.7		)	(13.5		)	(0.4		)	(6.8		)
Net amount	$	4.6		$	7.9		$	12.2		$	0.5


*	Includes cash collateral posted of $12.8 million and $6.4 million as of December 31, 2015 and 2014, respectively.

NOTE 18—VARIABLE INTEREST ENTITIES

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



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

American Transmission Company

We own approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. We do not have the power to direct the activities that most significantly impact ATC's economic performance. We instead account for ATC as an equity method investment. See Note 4, Investment in American Transmission Company, for more information.

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

Purchased Power Agreement

We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately 6 years. We have examined the risks of the entity, including operations and maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement.

We have approximately $130.5 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the years ended December 31, 2015, 2014, and 2013 were $53.6 million, $53.0 million, and $50.3 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 19—REGULATORY ENVIRONMENT

2015 Wisconsin Rate Order

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

•

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


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


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


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


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


•	A rate increase of approximately $1.2 million (7.3%) for our Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016.

Our authorized ROE was set at 10.2%, and our common equity component remained at an average of 51%. The PSCW order reaffirmed the deferral of our transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW approved a change in rate design for us, which includes higher fixed charges to better match the



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related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues we will receive under the PIPP SSR agreements. Under escrow accounting, we will record SSR revenues from MISO of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference will be deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference will be deferred and recovered from customers with interest, in a future rate case.

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

Earnings Sharing Agreement

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

2013 Wisconsin Rate Order

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

•

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


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


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


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


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


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

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

NOTE 20—MICHIGAN SETTLEMENT

In March 2015, we, along with Wisconsin Energy Corporation, entered into an Amended and Restated Settlement Agreement with the Attorney General of the State of Michigan, the Staff of the MPSC, Tilden Mining Company, and Empire Iron Mining Partnership (Amended Agreement) to resolve all objections these parties raised with the MPSC related to Wisconsin Energy Corporation's acquisition of Integrys. The agreement includes the following provisions:


•	The parties to the Amended Agreement agree that the acquisition satisfies the applicable requirements under Michigan law and should be approved by the MPSC.

•

We will not enter into an SSR agreement for the operation of PIPP so long as both mines, if operational, remain full requirements customers of ours until the earlier of (i) the date a new, clean generation plant located in the Upper Peninsula of Michigan commences commercial operation or (ii) December 31, 2019. The prior SSR agreement was terminated effective February 1, 2015, with the return of the mines as full requirements customers.



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•	Wisconsin Energy Corporation commits to invest, either through an ownership interest or a purchased power agreement, or to have, if formed, a future Michigan jurisdictional utility invest, in a plant subject to the issuance of a Certificate of Necessity from the MPSC. The costs of this plant would be recovered from Michigan customers.

In addition, in March 2015, we entered into a special contract with each of the mines to provide full requirements electric service through December 31, 2019.

In April 2015, the MPSC approved the acquisition of Integrys, the Amended Agreement, and the special contracts with the two mines.

NOTE 21—SEGMENT INFORMATION

At December 31, 2015, we reported three segments, which are described below. We manage our reportable segments separately due to their different operating and regulatory environments.


•	Our electric utility segment is engaged in the generation, distribution, and sale of electricity in southeastern (including metropolitan Milwaukee), east central, and northern Wisconsin and the Upper Peninsula of Michigan.


•	Our natural gas utility segment is engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.


•	Our steam utility segment produces, distributes, and sells steam to space heating and processing customers in metropolitan Milwaukee, Wisconsin.

Operating income is used to measure segment profitability and to allocate resources to our utility businesses. Total asset information is not provided for our reportable segments since, as an integrated electric, natural gas, and steam utility company, significant assets are not dedicated to a specific reportable segment. Reporting assets by segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the reportable segments on a stand-alone basis.

All of our operations and assets are located within the United States. The following tables show summarized financial information concerning our reportable segments for the years ended December 31, 2015, 2014, and 2013.



2015 (in millions)	Electric Utility		Natural Gas Utility		Steam Utility		Wisconsin Electric Power Company Consolidated
Operating revenues *	$	3,413.4	$	399.7	$	41.0	$	3,854.1
Other operation and maintenance	1,309.1		59.2		16.6		1,384.9
Depreciation and amortization	270.4		29.1		4.5		304.0
Operating income	582.7		60.6		5.6		648.9
Equity in earnings of transmission affiliate	47.8		—		—		47.8
Capital expenditures	444.6		71.7		2.9		519.2



2014 (in millions)	Electric Utility		Natural Gas Utility		Steam Utility		Wisconsin Electric Power Company Consolidated
Operating revenues *	$	3,401.1	$	614.2	$	44.1	$	4,059.4
Other operation and maintenance	1,268.9		70.0		17.5		1,356.4
Depreciation and amortization	244.1		30.5		3.7		278.3
Operating income	565.6		77.2		7.6		650.4
Equity in earnings of transmission affiliate	57.9		—		—		57.9
Capital expenditures	489.3		69.3		3.2		561.8



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2013 (in millions)	Electric Utility		Natural Gas Utility		Steam Utility		Wisconsin Electric Power Company Consolidated
Operating revenues *	$	3,308.7	$	451.9	$	39.6	$	3,800.2
Other operation and maintenance	1,323.8		75.0		18.5		1,417.3
Depreciation and amortization	201.5		25.5		3.6		230.6
Operating income	533.2		69.8		2.9		605.9
Equity in earnings of transmission affiliate	60.2		—		—		60.2
Capital expenditures	467.8		60.0		11.1		538.9


*	We account for all intersegment revenues at rates established by the PSCW. Intersegment revenues were not material.

NOTE 22—QUARTERLY FINANCIAL INFORMATION (Unaudited)



(in millions)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2015
Operating revenues	$	1,084.6	$	883.0	$	981.1	$	905.4	$	3,854.1
Operating income	204.7		128.7		169.8		145.7		648.9
Net income attributed to common shareholder	121.4		74.6		100.1		79.6		$	375.7

2014
Operating revenues	$	1,226.7	$	905.7	$	937.8	$	989.2	$	4,059.4
Operating income	221.8		144.2		156.2		128.2		650.4
Net income attributed to common shareholder	127.0		90.0		89.8		69.9		376.7

Due to various factors, the quarterly results of operations are not necessarily comparable.

NOTE 23—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.

Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have on our financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We are currently assessing the effects this guidance may have on our financial statements.



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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, 2015.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

This Annual 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 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On June 29, 2015, our parent company acquired Integrys. WEC Energy Group is currently in the process of integrating and aligning the operations, processes, and internal controls of the combined company. See Note 2, Acquisition, for more information regarding the acquisition.

ITEM 9B. OTHER INFORMATION

None.



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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 28, 2016 (the "2016 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 2016 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 Wisconsin Electric, 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 2016 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 2016 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 2016 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.	49

	Consolidated Income Statements for the three years ended December 31, 2015, 2014, and 2013.	50

	Consolidated Balance Sheets at December 31, 2015 and 2014.	51

	Consolidated Statements of Cash Flows for the three years ended December 31, 2015, 2014, and 2013.	52

	Consolidated Statements of Equity for the three years ended December 31, 2015, 2014, and 2013.	53

	Consolidated Statements of Capitalization at December 31, 2015 and 2014.	54

	Notes to Consolidated Financial Statements.	55

2.	Financial Statement Schedules Included in Part IV of This Report

	Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2015, 2014, and 2013.	93

	Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.

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



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SCHEDULE II

WISCONSIN ELECTRIC POWER COMPANY

VALUATION AND QUALIFYING ACCOUNTS



Allowance for Doubtful Accounts (in millions)	Balance at Beginning of the Period		Expense ⁽¹⁾		Deferral		Net Write-offs ⁽²⁾			Balance at End of the Period
December 31, 2015	$	46.8	$	30.6	$	0.3	$	(34.7	)	$	43.0
December 31, 2014	$	39.7	$	31.3	$	10.0	$	(34.2	)	$	46.8
December 31, 2013	$	36.7	$	31.4	$	2.7	$	(31.1	)	$	39.7


⁽¹⁾	Net of recoveries


⁽²⁾	Represents amounts written off to the reserve, net of adjustments to regulatory assets.



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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/GALE E. KLAPPA
Date:	February 26, 2016	Gale E. Klappa, Chairman of the Board and
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



/s/GALE E. KLAPPA		February 26, 2016
Gale E. Klappa, Chairman of the Board and Chief Executive
Officer and Director -- Principal Executive Officer

/s/J. PATRICK KEYES		February 26, 2016
J. Patrick Keyes, Executive Vice President and Chief
Financial Officer and Director -- Principal Financial Officer

/s/WILLIAM J. GUC		February 26, 2016
William J. Guc, Vice President and
Controller -- Principal Accounting Officer

/s/J. KEVIN FLETCHER		February 26, 2016
J. Kevin Fletcher, Director

/s/ALLEN L. LEVERETT		February 26, 2016
Allen L. Leverett, Director

/s/SUSAN H. MARTIN		February 26, 2016
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, 2015

The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)



Number	Exhibit
3	Articles of Incorporation and By-laws

	3.1*	Restated Articles of Incorporation of Wisconsin Electric Power Company, as amended and restated effective January 10, 1995. (Exhibit (3)-1 to Wisconsin Electric Power Company's 12/31/94 Form 10-K.)

	3.2*	Bylaws of Wisconsin Electric Power Company, as amended to May 1, 2000. (Exhibit 3.1 to Wisconsin Electric Power Company's 03/31/00 Form 10-Q.)

4	Instruments defining the rights of security holders, including indentures

	4.1*	Reference is made to Article III of the Restated Articles of Incorporation of Wisconsin Electric Power Company. (Exhibit 3.1 herein.)

	Indentures and Securities Resolutions:

	4.2*	Indenture for Debt Securities of Wisconsin Electric Power Company (the "Wisconsin Electric Indenture"), dated December 1, 1995. (Exhibit (4)-1 to Wisconsin Electric's 12/31/95 Form 10-K.)

	4.3*	Securities Resolution No. 1 of Wisconsin Electric under the Wisconsin Electric Indenture, dated December 5, 1995. (Exhibit (4)-2 to Wisconsin Electric's 12/31/95 Form 10-K.)

	4.4*	Securities Resolution No. 3 of Wisconsin Electric under the Wisconsin Electric Indenture, dated May 27, 1998. (Exhibit (4)-1 to Wisconsin Electric's 06/30/98 Form 10-Q.)

	4.5*	Securities Resolution No. 5 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to Wisconsin Electric's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)

	4.6*	Securities Resolution No. 7 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 2, 2006. (Exhibit 4.1 to Wisconsin Electric's 11/02/06 Form 8-K.)

	4.7*	Securities Resolution No. 10 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2009. (Exhibit 4.1 to Wisconsin Electric's 12/08/09 Form 8-K.)

	4.8*	Securities Resolution No. 11 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of September 7, 2011. (Exhibit 4.1 to Wisconsin Electric's 09/07/11 Form 8-K.)

	4.9*	Securities Resolution No. 12 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 5, 2012. (Exhibit 4.1 to Wisconsin Electric's 12/05/12 Form 8-K.)

	4.10*	Securities Resolution No. 13 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of June 10, 2013. (Exhibit 4.1 to Wisconsin Electric’s 06/10/13 Form 8-K.)

	4.11*	Securities Resolution No. 14 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 12, 2014. (Exhibit 4.1 to Wisconsin Electric's 05/12/14 Form 8-K.)

	4.12*	Securities Resolution No. 15 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 14, 2015. (Exhibit 4.1 to Wisconsin Electric's 05/14/15 Form 8-K.)



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Number	Exhibit

	4.13*	Securities Resolution No. 16 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 13, 2015. (Exhibit 4.1 to Wisconsin Electric's 11/13/15 Form 8-K.)

		Certain agreements and instruments with respect to unregistered long-term debt not exceeding 10 percent of the total assets of the Registrant and its subsidiary on a consolidated basis have been omitted as permitted by related instructions. The Registrant agrees pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreements and instruments.

10	Material Contracts

	10.1*	WEC Energy Group Supplemental Pension Plan, Amended and Restated Effective as of January 1, 2016. (Exhibit 10.1 to WEC Energy Group's 12/31/2015 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 12/31/2015 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, 2016. (Exhibit 10.3 to WEC Energy Group's 12/31/2015 Form 10-K (File No. 001-09057).)** See Note.

	10.4*	Directors' Deferred Compensation Plan of Wisconsin Energy Corporation, as amended and restated as of May 1, 2004 (the "Legacy DDCP"). (Exhibit 10.3 to Wisconsin Energy Corporation's 06/30/04 Form 10-Q (File No. 001-09057).)** See Note.

	10.5*	First Amendment to the Legacy DDCP, effective as of January 1, 2005. (Exhibit 10.15 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.6*	WEC Energy Group Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2016. (Exhibit 10.6 to WEC Energy Group's 12/31/2015 Form 10-K (File No. 001-09057).)** See Note.

	10.7*	WEC Energy Group Non-Qualified Retirement Savings Plan, Amended and Restated Effective as of January 1, 2016. (Exhibit 10.7 to WEC Energy Group's 12/31/2015 Form 10-K (File No. 001-09057).)** See Note.

	10.8*	Wisconsin Energy Corporation Death Benefit Only Plan, as amended and restated as of July 22, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/10 Form 10-Q (File No. 001-09057).)** See Note.

	10.9*	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.

	10.10*	WEC Energy Group Amended and Restated Executive Severance Policy, effective as of January 1, 2008. (Exhibit 10.18 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.11*	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.

	10.12*	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.

	10.13*	Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Allen L. Leverett, dated as of December 30, 2008. (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/08 Form 10-K (File No. 001-09057).)** See Note.

	10.14*	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.

	10.15*	Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of December 20, 2010. (Exhibit 10.20 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.



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Number	Exhibit

	10.16*	Amendment to the Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of August 15, 2011. (Exhibit 10.21 to Wisconsin Energy Corporation's 12/31/12 Form 10-K (File No. 001-09057).)** See Note.

	10.17*	Terms of Employment for Susan H. Martin. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/12 Form 10-Q (File No. 001-09057).)**See Note.

	10.18*	Letter Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q (File No. 001-09057).)** See Note.

	10.19*	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.

	10.20*	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.

	10.21*	Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/07 Form 10-Q (File No. 001-09057).)** See Note.

	10.22*	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.

	10.23*	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.

	10.24*	2016 WEC Energy Group Terms and Conditions Governing Director Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan (Exhibit 10.24 to WEC Energy Group's 12/31/15 Form 10-K (File No. 001-09057).)** See Note.

	10.25*	WEC Energy Group Performance Unit Plan, amended and restated effective as of January 1, 2016. (Exhibit 10.1 to WEC Energy Group's 12/03/15 Form 8-K (File No. 001-09057).)** See Note.

	10.26*	Wisconsin Energy Corporation Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.

	10.27*	2016 WEC Energy Group Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.27 to WEC Energy Group’s 12/31/15 Form 10-K (File No. 001-09057).)** See Note.

	10.28*	Wisconsin Energy Corporation Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/04/14 Form 8-K (File No. 001-09057).)** See Note.

	10.29*	2016 WEC Energy Group Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.29 to WEC Energy Group’s Form 12/31/15 Form 10-K (File No. 001-09057).)** See Note.

	10.30*	Port Washington I Facility Lease Agreement between Port Washington Generating Station LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.7 to Wisconsin Electric's 06/30/03 Form 10-Q.)

	10.31*	Port Washington II Facility Lease Agreement between Port Washington Generating Station LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.8 to Wisconsin Electric's 06/30/03 Form 10-Q.)

	10.32*	Elm Road I Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)



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Number	Exhibit
	10.33*	Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K (File No. 001-09057).)

	10.34*	Point Beach Nuclear Plant Power Purchase Agreement between FPL Energy Point Beach, LLC and Wisconsin Electric Power Company, dated as of December 19, 2006 (the "PPA"). (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/08 Form 10-Q (File No. 001-09057).)

	10.35*	Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC, dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K (File No. 001-09057).)

	10.36*	Terms and Conditions for July 31, 2015 Special Restricted Stock Award. (Exhibit 10.1 to WEC Energy Group’s 6/30/15 Form 10-Q (File No. 001-09057).)** See Note.

	Note: Two asterisks (**) identify management contracts and executive compensation plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of Form 10-K.

21	Subsidiaries of the registrant

	21.1	Subsidiaries of Wisconsin Electric Power Company.

23	Consents of experts and counsel

	23.1	Deloitte & Touche LLP – Milwaukee, WI, Consent of Independent Registered Public Accounting Firm.

31	Rule 13a-14(a)/15d-14(a) Certifications

	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications

	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Interactive Data File



2015 Form 10-K	98	Wisconsin Electric Power Company

WISCONSIN ELECTRIC POWER CO - FORM 10-K - February 26, 2016

Attached files

WISCONSIN ELECTRIC POWER CO Reports