Edgar Filing: WEC ENERGY GROUP, INC.

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 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.

001-09057	WEC ENERGY GROUP, INC.	39-1391525
	(A Wisconsin Corporation) 231 West Michigan Street P. O. Box 1331 Milwaukee, WI 53201 414-221-2345

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



Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, $.01 Par Value		New York Stock Exchange

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

None

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. [ ]

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 [X]	Accelerated filer [ ]
	Non-accelerated filer [ ]	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]

The aggregate market value of the common stock of WEC Energy Group, Inc. held by non-affiliates was $14.2 billion based upon the reported closing price of such securities as of June 30, 2015.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (January 31, 2016):

Common Stock, $.01 par value, 315,652,119 shares outstanding

Documents incorporated by reference:

Portions of WEC Energy Group, Inc.'s Definitive Proxy Statement on Schedule 14A for its Annual Meeting of Stockholders, to be held on May 5, 2016, are incorporated by reference into Part III hereof.

Table of Contents

WEC ENERGY GROUP, INC.

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 ENERGY OPERATIONS			3
	C.	NON-UTILITY OPERATIONS			16
	D.	REGULATION			17
	E.	ENVIRONMENTAL COMPLIANCE			20
	F.	EMPLOYEES			21
ITEM 1A.	RISK FACTORS				23
ITEM 1B.	UNRESOLVED STAFF COMMENTS				32
ITEM 2.	PROPERTIES				33
ITEM 3.	LEGAL PROCEEDINGS				35
ITEM 4.	MINE SAFETY DISCLOSURES				36
	EXECUTIVE OFFICERS OF THE REGISTRANT				37
PART II					39
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES				39
ITEM 6.	SELECTED FINANCIAL DATA				40
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				41
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				64
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA				65
	A.	Reports of Independent Registered Public Accounting Firm			65
	B.	Consolidated Income Statements			67
	C.	Consolidated Statements of Comprehensive Income			68
	D.	Consolidated Balance Sheets			69
	E.	Consolidated Statements of Cash Flows			70
	F.	Consolidated Statements of Equity			71
	G.	Consolidated Statements of Capitalization			72
	H.	Notes to Consolidated Financial Statements			74
		Note 1	Summary of Significant Accounting Policies	74
		Note 2	Acquisition	81
		Note 3	Dispositions	84
		Note 4	Investment in American Transmission Company	85
		Note 5	Supplemental Cash Flow Information	86
		Note 6	Regulatory Assets and Liabilities	86
		Note 7	Property, Plant, and Equipment	87
		Note 8	Jointly Owned Facilities	88
		Note 9	Asset Retirement Obligations	88
		Note 10	Goodwill and Other Intangible Assets	89
		Note 11	Common Equity	89
		Note 12	Preferred Stock	93
		Note 13	Short-Term Debt and Lines of Credit	93



2015 Form 10-K	i	WEC Energy Group, Inc.

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		Note 14	Long-Term Debt and Capital Lease Obligations	94
		Note 15	Income Taxes	97
		Note 16	Guarantees	100
		Note 17	Employee Benefits	100
		Note 18	Commitments and Contingencies	105
		Note 19	Fair Value Measurements	113
		Note 20	Derivative Instruments	115
		Note 21	Variable Interest Entities	116
		Note 22	Regulatory Environment	116
		Note 23	Michigan Settlement	120
		Note 24	Segment Information	121
		Note 25	Quarterly Financial Information (Unaudited)	122
		Note 26	New Accounting Pronouncements	123
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE				124
ITEM 9A.	CONTROLS AND PROCEDURES				124
ITEM 9B.	OTHER INFORMATION				124
PART III					125
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE OF THE REGISTRANT				125
ITEM 11.	EXECUTIVE COMPENSATION				125
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS				125
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE				126
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES				126
PART IV					127
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES				127
SCHEDULE I — CONDENSED PARENT COMPANY FINANCIAL STATEMENTS					128
	A.	Income Statements			128
	B.	Statements of Comprehensive Income			129
	C.	Balance Sheets			130
	D.	Statements of Cash Flows			131
	E.	Notes to Parent Company Financial Statements			132
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS					134
SIGNATURES					135
EXHIBIT INDEX					137



2015 Form 10-K	ii	WEC Energy Group, Inc.

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GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:



Subsidiaries and Affiliates
ATC		American Transmission Company LLC
Bostco		Bostco LLC
DATC		Duke-American Transmission Company
ERGSS		Elm Road Generating Station Supercritical, LLC
Integrys		Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
ITF		Integrys Transportation Fuels, LLC
MERC		Minnesota Energy Resources Corporation
MGU		Michigan Gas Utilities Corporation
NSG		North Shore Gas Company
PDL		WPS Power Development LLC
PELLC		Peoples Energy, LLC
PGL		The Peoples Gas Light and Coke Company
WBS		WEC Business Services, LLC
We Power		W.E. Power, LLC
WECC		Wisconsin Energy Capital Corporation
Wisconsin Electric		Wisconsin Electric Power Company
Wisconsin Gas		Wisconsin Gas LLC
Wispark		Wispark LLC
Wisvest		Wisvest LLC
WPS		Wisconsin Public Service Corporation

Certain Assets
MCPP		Milwaukee County Power Plant
OC 1		Oak Creek Expansion Unit 1
OC 2		Oak Creek Expansion Unit 2
PIPP		Presque Isle Power Plant
PSGS		Paris 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
ICC		Illinois Commerce Commission
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
MPUC		Minnesota Public Utilities Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources



2015 Form 10-K	iii	WEC Energy Group, Inc.

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

Environmental Terms
Act 141		2005 Wisconsin Act 141
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
Bcf		Billion Cubic Feet
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)
MDth		One thousand Dekatherms
MW		Megawatt(s) (One MW equals one million Watts)
MWh		Megawatt-hour(s)

Other Terms and Abbreviations
ALJ		Administrative Law Judge
AMRP		Accelerated Natural Gas Main Replacement Program
ARRs		Auction Revenue Rights
CNG		Compressed Natural Gas
Compensation Committee		Compensation Committee of the Board of Directors
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



2015 Form 10-K	iv	WEC Energy Group, Inc.

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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	v	WEC Energy Group, Inc.

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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, dividend payout ratios, 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, us, or any of our subsidiaries;


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


•	Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances;



2015 Form 10-K	1	WEC Energy Group, Inc.

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•	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;


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


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


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


•	The terms and conditions of the governmental and regulatory approvals of the acquisition of Integrys that could reduce anticipated benefits and our ability to successfully integrate the operations of the combined company;


•	The risk associated with the values of goodwill and other intangible assets and their possible impairment;


•	Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;


•	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	WEC Energy Group, Inc.

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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 WEC Energy Group, Inc. The term "utility" refers to the regulated activities of the electric and natural gas utility companies, while the term "non-utility" refers to the activities of the electric and natural gas utility companies that are not regulated, as well as We Power. The term "nonregulated" refers to activities at WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF. References to "Notes" are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

For more information about our business operations, including financial and geographic information about each reportable business segment, see Note 24, Segment Information, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

WEC Energy Group, Inc.

We were incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. Our wholly owned subsidiaries provide regulated natural gas and electricity, as well as nonregulated renewable energy. Another subsidiary, ITF, provides CNG products and services and was recorded as held for sale as of December 31, 2015. See Note 3, Dispositions, for more information. In addition, we have an approximately 60% equity interest in ATC (an electric transmission company operating in Illinois, Michigan, Minnesota, and Wisconsin). At December 31, 2015, we had six reportable segments which are discussed below. For additional information about our reportable segments, see Note 24, Segment Information.

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, on our 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 ENERGY OPERATIONS

Wisconsin Segment

Electric Utility Operations

For the periods presented in this Annual Report on Form 10-K, our electric utility operations included operations of Wisconsin Electric for all periods and operations for WPS beginning July 1, 2015, due to the acquisition of Integrys and its subsidiaries. Wisconsin Electric, which is the largest electric utility in the state of Wisconsin, generates and distributes electric energy to approximately 1,140,100 customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, northern Wisconsin, and Michigan's Upper Peninsula. WPS generates and distributes electric energy to approximately 449,200 customers located in northeastern Wisconsin and Michigan's Upper Peninsula.



2015 Form 10-K	3	WEC Energy Group, Inc.

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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 ⁽¹⁾		2014		2013
Operating revenues (in millions)
Residential	$	1,398.5	$	1,199.3	$	1,208.6
Small commercial and industrial	1,234.3		1,052.9		1,048.0
Large commercial and industrial	857.6		637.0		711.9
Other	26.9		23.0		23.4
Total retail revenues	3,517.3		2,912.2		2,991.9
Wholesale	181.4		131.9		143.7
Resale	248.7		264.1		143.2
Other operating revenues	77.5		87.8		28.4
Total	4,024.9		3,396.0		3,307.2
Electric customer choice ⁽²⁾	2.6		5.1		1.5
Total operating revenues	$	4,027.5	$	3,401.1	$	3,308.7

Customers – end of year (in thousands)
Residential	1,414.1		1,015.0		1,010.5
Small commercial and industrial	171.1		115.4		114.6
Large commercial and industrial	1.0		0.7		0.7
Other	3.1		2.5		2.6
Total customers	1,589.3		1,133.6		1,128.4

Customers – average (in thousands)	1,584.4		1,130.7		1,126.9


⁽¹⁾	Includes the operations of WPS beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.


⁽²⁾	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 87.3% of total electric operating revenues, while wholesale (including resale) electric revenues accounted for 10.7% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Wisconsin Segment Contribution to Operating Income for information on MWh sales by customer class.

Our electric utilities 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.

Our electric utilities 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. Wisconsin Electric 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,



2015 Form 10-K	4	WEC Energy Group, Inc.

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see Note 23, 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.

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 6.0%, 5.3%, and 5.9% of total electric energy sales during 2015, 2014, and 2013, respectively. Wholesale revenues accounted for 4.5%, 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 20.9%, 18.5%, and 13.3% of total electric energy sales during 2015, 2014, and 2013, respectively. Resale revenues accounted for 6.2%, 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 2% 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. 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 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	4,955	3,707	3,822
Natural gas:
Combined cycle	1,636	1,082	1,082
Steam turbine ⁽²⁾	305	118	—
Natural gas/oil peaking units ⁽³⁾	1,412	962	962
Renewables ⁽⁴⁾	269	155	155
Total rated capacity by fuel type	8,577	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, as well as Weston Unit 2, which was converted from coal to natural gas in 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	WEC Energy Group, Inc.

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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 generation units:
Coal	49.6	%	51.5	%	55.2	%	53.6	%
Natural gas:
Combined cycle	18.7	%	14.6	%	8.7	%	10.1	%
Steam turbine	0.8	%	1.2	%	0.2	%	—	%
Natural gas/oil peaking units	0.1	%	0.6	%	0.2	%	0.2	%
Renewables	3.5	%	3.4	%	3.8	%	3.3	%
Total company-owned generation units	72.7	%	71.3	%	68.1	%	67.2	%
Power purchase contracts:
Nuclear	16.6	%	20.5	%	25.4	%	27.1	%
Natural gas	2.5	%	1.4	%	2.1	%	2.1	%
Renewables	2.1	%	1.5	%	2.7	%	3.1	%
Other	2.9	%	3.5	%	0.9	%	0.5	%
Total power purchase contracts	24.1	%	26.9	%	31.1	%	32.8	%
Purchased power from MISO	3.2	%	1.8	%	0.8	%	—	%
Total purchased power	27.3	%	28.7	%	31.9	%	32.8	%
Total electric utility supply	100.0	%	100.0	%	100.0	%	100.0	%

Coal-Fired Generation

Our coal-fired generation consists of nine operating plants with a rated capacity of 4,955 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 consists of nine operating plants, including peaking units, with a rated capacity of 3,173 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 1,217 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 30 operating plants with a total installed capacity of 168 MW and a rated capacity of 146 MW as of December 31, 2015. All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Wind

We have six wind sites, consisting of 280 turbines, with an installed capacity of 447 MW and a rated capacity of 73 MW as of December 31, 2015.



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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.

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 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 – D. Regulation.

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



	2015		2014		2013
Coal	$	25.57	$	27.68	$	27.97
Natural gas combined cycle	17.66		40.64		32.22
Natural gas/oil peaking units	56.99		129.83		83.95
Purchased power	43.50		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.

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.

Wisconsin Electric and WPS both have a PSCW-approved hedging program that allows them to hedge up to 75% of their potential risks related to fuel surcharge exposure. Wisconsin Electric and WPS also have a program that allows them to hedge up to 65% and 75%, respectively, of their estimated natural gas use for electric generation in order to help manage their natural gas price risk. These hedging programs are generally implemented on a 36-month forward-looking basis. The results of all of these programs are reflected in the average costs of natural gas and purchased power.



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Coal Supply

We diversify the coal supply for our electric generating facilities and jointly-owned plants by purchasing coal from several mines in Wyoming, as well as from various other states. For 2016, approximately 78% of our total projected coal requirements of approximately 16 million tons are contracted under fixed-price contracts. See Note 18, 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		13,281
2017		9,303
2018		5,153

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 participants 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 – D. Regulation.

Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. As of December 31, 2015, our power purchase commitments with unaffiliated parties for the next five years is 1,432 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 utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. Our generating plants performed as expected during the warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, Wisconsin Electric did not require public appeals for conservation, and it did not interrupt or curtail service to non-firm customers who participate in load management programs. In addition, WPS did not require any public appeals for conservation, and it did not interrupt or curtail service to non-firm customers who participate in load management programs for capacity reasons. However, WPS did have service curtailments for economic reasons.

Competition

Our electric utilities 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. Our electric utilities compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.



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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 18, 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.

Natural Gas Utility Operations

For the periods presented in this Annual Report on Form 10-K, our Wisconsin natural gas utility operations include Wisconsin Gas's and Wisconsin Electric's natural gas operations for all periods and WPS's natural gas operations, including in the Upper Peninsula of Michigan, beginning July 1, 2015, due to the acquisition of Integrys and its subsidiaries.

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. Together our natural gas distribution utilities are the largest in Wisconsin, and we operate throughout the state, including the City of Milwaukee and surrounding areas, northeastern Wisconsin, and large areas of both central and western Wisconsin.

Natural Gas Utility Operating Statistics

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



	Year Ended December 31
	2015 ⁽¹⁾		2014		2013
Operating revenues (in millions)
Residential	$	696.2	$	925.3	$	712.6
Commercial and industrial	332.8		506.0		356.1
Total retail revenues	1,029.0		1,431.3		1,068.7
Transport	62.8		54.2		50.8
Other operating revenues	30.8		10.6		(5.8		)
Total	$	1,122.6	$	1,496.1	$	1,113.7

Customers – end of year (in thousands)
Residential	1,299.7		993.9		985.7
Commercial and industrial	123.4		93.3		92.4
Transport	2.6		1.8		1.7
Total customers	1,425.7		1,089.0		1,079.8

Customers – average (in thousands)	1,417.8		1,081.5		1,074.9


⁽¹⁾	Includes the operations of WPS beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.

Natural Gas Deliveries

Our gas therm deliveries include customer-owned transported natural gas. Transported natural gas accounted for approximately 50.7% of the total volumes delivered during 2015, 42.3% during 2014, and 43.1% during 2013. Our peak daily send-out during 2015 was 18.2 million therms on January 7, 2015.



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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, paper, and metal. Fuel used for Wisconsin Electric's electric generation represents our largest transportation customer. Natural gas therms delivered to Wisconsin Electric for electric generation represented 15.3%, 9.3%, and 10.4% of the total volumes delivered during 2015, 2014, and 2013, respectively.

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 18, 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.

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 Wisconsin natural gas utilities' forecasted design peak-day throughput is 30.8 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. As local distribution companies, our Wisconsin natural gas utilities must contract for capacity and supply sufficient to meet the firm peak-day demand of our 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 GCRMs. During 2015, we continued to participate in the secondary markets. For information on the GCRMs, 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.



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Hedging Natural Gas Supply Prices

Wisconsin Electric and Wisconsin Gas 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. WPS has PSCW approval to hedge up to 67% of planned winter demand using a combination of planned withdrawals from storage and NYMEX financial instruments. These approvals allow these companies to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through their respective GCRMs. Hedge targets (volumes) are provided annually to the PSCW as part of each company's three-year natural gas supply plan and risk management filing.

To the extent that opportunities develop and physical supply operating plans are supportive, Wisconsin Electric, Wisconsin Gas, and WPS also have PSCW approval to utilize NYMEX-based natural gas derivatives to capture favorable forward-market price differentials. These approvals provide for 100% of the related proceeds to accrue to these companies' respective GCRMs.

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 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 Operations

Wisconsin Electric has 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. Wisconsin Electric operates a district steam system in downtown Milwaukee and the near south side of Milwaukee, and steam is supplied to this system from VAPP. Wisconsin Electric also operates 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.



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Steam Utility Operating Statistics

Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions. Certain sections of this Annual Report on Form 10-K combine steam operating revenues with electric operating revenues.

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

Illinois Segment

Our Illinois segment includes the natural gas utility operations of PGL and NSG. PGL and NSG, both Illinois corporations, began operations in 1855 and 1900, respectively. We acquired PGL and NSG as a result of the acquisition of Integrys on June 29, 2015. Our customers are located in Chicago and the northern suburbs of Chicago.

Illinois Utilities Operating Statistics

The following table shows certain Illinois utility operating statistics since the acquisition of Integrys.



	Six Months Ended
	December 31,
	2015
Operating revenues (in millions)
Residential	$	309.8
Commercial and industrial	50.4
Total retail revenues	360.2
Transport	97.1
Other operating revenues	46.1
Total	$	503.4

Customers – end of year (in thousands)
Residential	838.2
Commercial and industrial	46.2
Transport	107.8
Total customers	992.2

Customers – average (in thousands)	982.3

Natural Gas Supply, Pipeline Capacity and Storage

We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns with safe, reliable natural gas supplies at the best value.

Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases, contracted and owned storage, peak-shaving facilities, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.

For more information on our natural gas utility supply and transportation contracts, see Note 18, Commitments and Contingencies.



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We contract with local distribution companies and interstate pipelines to purchase firm transportation services. We believe that having multiple pipelines that serve our natural gas service territory benefits our customers by improving reliability, providing access to a diverse supply of natural gas, and fostering competition among these service providers. These benefits can lead to favorable conditions for our Illinois utilities when negotiating new agreements for transportation and storage services. Our Illinois utilities further reduce their supply cost volatility through the use of financial instruments, such as commodity futures, swaps, and options as part of their hedging programs. They hedge between 25% and 50% of natural gas purchases, with a target of 37.5%.

We own a 38.3 Bcf storage field (Manlove Field in central Illinois) and contract with various other underground storage service providers for additional storage services. Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas on a year-round basis, which provides a hedge against supply cost volatility. We also own a natural gas pipeline system that connects Manlove Field to Chicago and eight major interstate pipelines. These assets are directed primarily to serving rate-regulated retail customers and are included in our regulatory rate base. We also use a portion of these company-owned storage and pipeline assets as a natural gas hub, which consists of providing transportation and storage services in interstate commerce to our wholesale customers. Customers deliver natural gas to us for storage through an injection into the storage reservoir, and we return the natural gas to the customers under an agreed schedule through a withdrawal from the storage reservoir. Title to the natural gas does not transfer to us. We recognize service fees associated with the natural gas hub services provided to wholesale customers. These service fees reduce the cost of natural gas and services charged to retail customers in rates.

We had adequate capacity to meet all firm natural gas demand obligations during 2015 and expect to have adequate capacity to meet all firm demand obligations during 2016. Our Illinois utilities' forecasted design peak-day throughput is 25.4 million therms for the 2015 through 2016 heating season.

Accelerated Natural Gas Main Replacement Program

PGL is continuing work on the AMRP, a 20-year project that began in 2011 under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved qualifying infrastructure plant rider, which is in effect through 2023. For information on investigations related to the AMRP, see Note 22, Regulatory Environment.

Seasonality

Our Illinois utilities' 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 November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

Competition

Although our Illinois utilities' rates are regulated by the ICC, we still face varying degrees of competition from other entities and other forms of energy available to consumers. Absent extraordinary circumstances, potential competitors are not allowed to construct competing natural gas distribution systems in our service territory due to a judicial doctrine known as the "first in the field." In addition, we believe it would be impractical to construct competing duplicate distribution facilities due to the high cost of installation.

Since 2002, all our Illinois utilities' natural gas customers have had the opportunity to choose a natural gas supplier other than us. As a result, we offer natural gas transportation service to enable customers to directly manage their energy costs. Transportation customers purchase natural gas directly from third-party natural gas suppliers and use our distribution system to transport the natural gas to their facilities. We still earn a distribution charge for transporting the natural gas for these customers. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs.



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An interstate pipeline may seek to provide transportation service directly to end users, which would bypass our natural gas transportation service. However, we have a bypass rate approved by the ICC, which allows us to negotiate rates with customers that are potential bypass candidates to help ensure that such customers use our transportation service.

Other States Segment

Our other states segment includes the natural gas utility operations of MERC and MGU. We acquired the natural gas distribution operations of MERC and MGU, located in Minnesota and Michigan, respectively, on June 29, 2015, with the acquisition of Integrys. MERC serves customers in various cities and communities throughout Minnesota, and MGU serves customers in the southern portion of lower Michigan.

Other States Utilities Operating Statistics

The following table shows certain other states utility operating statistics since the acquisition of Integrys.



	Six Months Ended
	December 31,
	2015
Operating revenues (in millions)
Residential	$	67.6
Commercial and industrial	38.8
Total retail revenues	106.4
Transport	11.5
Other operating revenues	31.4
Total	$	149.3

Customers – end of year (in thousands)
Residential	345.8
Commercial and industrial	33.8
Transport	23.0
Total customers	402.6

Customers – average (in thousands)	401.5

Natural Gas Supply, Pipeline Capacity and Storage

For more information on our natural gas utility supply and transportation contracts, see Note 18, Commitments and Contingencies.

We own a storage field (Partello in Michigan) and contract with various other underground storage service providers for additional storage services. Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas on a year-round basis, which provides a hedge against supply cost volatility. We contract with local distribution companies and interstate pipelines to purchase firm transportation services. We believe that having multiple pipelines that serve our natural gas service territory benefits our customers by improving reliability, providing access to a diverse supply of natural gas, and fostering competition among these service providers. These benefits can lead to favorable conditions for our other states utilities when negotiating new agreements for transportation and storage services. Our other states utilities further reduce their supply cost volatility through the use of financial instruments, such as commodity futures, swaps, and options as part of their hedging programs.



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MERC hedges up to 70% of planned winter demand using a combination of planned withdrawals from storage and NYMEX financial instruments. MGU hedges up to 20% of its planned annual purchases using NYMEX financial instruments.

Combined with our storage capability, management believes that the volume of gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Forecasted design peak-day throughput for our other states utilities segment is 8.2 million therms for the 2015 through 2016 heating season.

Seasonality

Our other states utilities' 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 November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

Competition

Although our other states utilities' rates are regulated by the MPUC and MSPC, we still face varying degrees of competition from other entities and other forms of energy available to consumers. Many large commercial and industrial customers have the ability to switch between natural gas and alternate fuels. Due to the volatility of energy commodity prices, we have seen customers with dual fuel capability switch to alternate fuels for short periods of time, then switch back to natural gas as market rates change.

MERC commercial and industrial customers have the opportunity to choose a natural gas supplier and all MGU customers have the opportunity to choose a natural gas supplier other than us. We offer natural gas transportation service and also offer interruptible natural gas sales to enable customers to better manage their energy costs. Transportation customers purchase natural gas directly from third-party natural gas suppliers and use our distribution systems to transport the natural gas to their facilities. We still earn a distribution charge for transporting the natural gas for these customers. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.

Electric Transmission Segment

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 Wisconsin Electric and WPS, 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 Wisconsin Electric and WPS are non-transmission owning members and customers of MISO. As of December 31, 2015, our ownership interest in ATC was approximately 60%. This increase over the December 31, 2014, ownership interest of approximately 26% was due to the acquisition of Integrys on June 29, 2015. 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



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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.

C. NON-UTILITY OPERATIONS

We Power Segment

We Power, through wholly owned subsidiaries, has designed and built approximately 2,350 MW of generation in Wisconsin as part of our PTF strategy. This generation is made up of capacity from the Oak Creek Expansion units, OC 1 and OC 2, which were placed in service in February 2010 and January 2011, respectively, and the PWGS units, PWGS 1 and PWGS 2, which were placed in service in July 2005 and May 2008, respectively. Two unaffiliated entities collectively own approximately 17%, or approximately 211 MW, of OC 1 and OC 2. All four of the PTF units are being leased to Wisconsin Electric under long-term leases (the Oak Creek units have 30-year leases and the PWGS units have 25-year leases). The PTF units are positioned to provide a significant portion of our future generation needs.

Our PTF strategy was designed to address Wisconsin Electric's electric supply needs by increasing the electric generating capacity in Wisconsin while allowing us to maintain a diversified fuel mix by including both new coal-fired plants and natural gas-fired plants. Because of the significant investment necessary to construct these generating units, we constructed the plants under Wisconsin's Leased Generation Law, which allows a non-utility affiliate to construct an electric generating facility and lease it to the public utility. The law allows a public utility that has entered into a lease approved by the PSCW to recover fully in its retail electric rates that portion of any payments under the lease that the PSCW has allocated to the public utility's Wisconsin retail electric service, and all other costs that are prudently incurred in the public utility's operation and maintenance of the electric generating facility allocated to the utility's Wisconsin retail electric service. In addition, the PSCW may not modify or terminate a lease it has approved under the Leased Generation Law except as specifically provided in the lease or the PSCW's order approving the lease. This law effectively created regulatory certainty in light of the significant investment being made to construct the units. All four PTF units were constructed under leases approved by the PSCW.

We are recovering our costs of the PTF units, including subsequent capital additions, through lease payments that are billed from We Power to Wisconsin Electric and then recovered in Wisconsin Electric's rates as authorized by the PSCW, the MPSC, and the FERC. Under the lease terms, our return is calculated using a 12.7% ROE and the equity ratio is assumed to be 55% for the Oak Creek units and 53% for the PWGS units.

For additional background information on our PTF strategy, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity and Capital Resources – Power the Future in Item 7. of our Annual Report on Form 10-K for the year ended December 31, 2007.

Corporate and Other Segment

The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, and the PELLC holding company, as well as the operations of Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF.

Bostco and Wispark develop and invest in real estate, and combined they had $72.7 million in real estate holdings at December 31, 2015. Wispark has developed several business parks and other commercial real estate projects, primarily in southeastern Wisconsin.

Wisvest was originally formed to develop, own, and operate electric generating facilities and to invest in other energy-related entities. However, Wisvest discontinued its development activity several years ago. At December 31, 2015, Wisvest's only operating asset and investment was Wisvest Thermal Energy Services, which provides chilled water services to the Milwaukee Regional Medical Center. During 2015, we entered into an agreement to sell the MCPP, including Wisvest Thermal Energy Services. This sale is expected to close during the first half of 2016.



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WECC was originally formed to invest in non-utility projects, such as low income housing developments. However, due to a focus on our regulated utility business, WECC sold many of its non-utility investments and no longer has significant operations.

WBS is a wholly owned centralized service company that provides administrative and general support services to our regulated utilities. WBS also provides certain administrative and support services to our nonregulated entities.

PDL owns distributed renewable projects, primarily solar, and a natural gas-fired cogeneration facility in Wisconsin known as the Combined Locks Energy Center. PDL's natural gas-fired facility is subject to market price volatility and is dispatched to produce energy only when it is economical to do so. PDL's renewable energy facilities rely on renewable resources, such as solar irradiance or landfill gas. There is no market price risk associated with the fuel supply of these facilities. However, production at these facilities can be intermittent due to the availability of the renewable energy resource.

ITF designs, builds, maintains, owns, and operates CNG fueling stations in multiple states. In addition, ITF manufactures its own compressor package, which includes a proprietary method of compressing natural gas. Since ITF's operations are inconsistent with our risk profile, we entered into an agreement to sell ITF in February 2016. See Note 3, Dispositions, for more information.

D. REGULATION

We are a holding company and are subject to the requirements of the Public Utility Holding Company Act of 2005 (PUHCA 2005). We also have various subsidiaries that meet the definition of a holding company under PUHCA 2005 and are also subject to its requirements.

Pursuant to the non-utility asset cap provisions of Wisconsin's public utility holding company law, the sum of certain assets of all non-utility affiliates in a holding company system may not exceed 25% of the assets of all public utility affiliates. However, among other items, the law exempts energy-related assets, including the generating plants constructed by We Power as part of our PTF strategy, from being counted against the asset cap provided that they are employed in qualifying businesses. We report to the PSCW annually our compliance with this law and provide supporting documentation to show that our non-utility assets are below the non-utility asset cap.

Regulated Utility Operations

In addition to the specific regulations noted above and below, our utilities are also subject to regulations, where applicable, of the EPA, the WDNR, the MDEQ, the Michigan Department of Natural Resources, the Illinois Environmental Protection Agency, the U.S. Army Corps of Engineers, the Minnesota Department of Natural Resources, and the Minnesota Pollution Control Agency.



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Rates

Our utilities' 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
Wisconsin Electric
Retail electric, natural gas, and steam		PSCW
Retail electric		MPSC
Wholesale power		FERC
WPS
Retail electric and natural gas		PSCW and MPSC
Wholesale power		FERC
Wisconsin Gas
Retail natural gas		PSCW
PGL
Retail natural gas		ICC
NSG
Retail natural gas		ICC
MERC
Retail natural gas		MPUC
MGU
Retail natural gas		MPSC

Embedded within Wisconsin Electric's and WPS’s electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require the utility to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of the utility's symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of the utility's approved fuel and purchased power cost plan. The deferred fuel and purchased power costs are subject to an excess revenues test. If the utility's 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 the utility's 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 GCRMs as approved by their respective state regulator. Generally, the GCRMs allow for a dollar-for-dollar recovery of prudently incurred natural gas costs.

For a summary of the significant mechanisms our utility subsidiaries had in place in 2015 that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts, see Note 1(d), Revenues and Customer Receivables.

In May 2015, the PSCW approved the acquisition of Integrys on the condition that Wisconsin Electric and Wisconsin Gas 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 rates are set for our regulated entities, see Note 22, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:



Regulatory Commission		Website
PSCW		https://psc.wi.gov/
ICC		https://www.icc.illinois.gov/
MPSC		http://www.michigan.gov/mpsc/
MPUC		http://mn.gov/puc/
FERC		http://www.ferc.gov/



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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 ⁽¹⁾
Wisconsin	$	3,374.9	83.0	%	$	2,934.0	85.2	%	$	2,914.4	87.0	%
Michigan	173.1		4.3	%	58.8		1.7	%	147.0		4.4	%
FERC – Wholesale	429.1		10.5	%	396.0		11.5	%	286.9		8.6	%
FERC – SSR ⁽²⁾	91.4		2.2	%	56.4		1.6	%	—		—	%
Total	4,068.5		100.0	%	3,445.2		100.0	%	3,348.3		100.0	%

Natural Gas ⁽¹⁾
Wisconsin	1,121.3		63.2	%	1,496.1		100.0	%	1,113.7		100.0	%
Illinois	503.4		28.4	%	—		—	%	—		—	%
Minnesota	98.3		5.5	%	—		—	%	—		—	%
Michigan	52.3		2.9	%	—		—	%	—		—	%
Total	1,775.3		100.0	%	1,496.1		100.0	%	1,113.7		100.0	%

Total utility operating revenues	$	5,843.8			$	4,941.3			$	4,462.0


⁽¹⁾	Includes the operations of WPS, PGL, NSG, MERC, and MGU beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.


⁽²⁾	See Note 22, 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 MISO Energy 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.

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 primarily fulfilled using our own capacity resources.



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Other Electric Regulations

Wisconsin Electric and WPS 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.

Wisconsin Electric and WPS are subject to Act 141 in Wisconsin and Public Act 295 in Michigan, which contain certain minimum requirements for renewable energy generation. See Note 18, 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, including PGL's natural gas hub, 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 utilities' 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 territories. 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 low-income customers of the utilities.

Non-Utility Operations

We Power, through wholly owned subsidiaries, constructed the new generating capacity in our PTF strategy. These facilities are being leased on a long-term basis to Wisconsin Electric. Environmental permits necessary for operating the facilities are the responsibility of the operating entity, Wisconsin Electric. We Power received determinations from the FERC that upon the transfer of the facilities by lease to Wisconsin Electric, We Power's subsidiaries would not be deemed public utilities under the Federal Power Act and thus would not be subject to the FERC's jurisdiction.

E. ENVIRONMENTAL COMPLIANCE

Our operations are subject to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation, and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental regulations or revisions to existing laws, including for example, additional regulation of GHG emissions, coal combustion products, air emissions, or wastewater discharges, could significantly increase these environmental compliance costs.

Anticipated expenditures for environmental compliance and remediation issues for the next three years are included in the estimated capital expenditures described in 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 18, Commitments and 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.



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F. EMPLOYEES

As of December 31, 2015, we had the following number of employees:



	Total Employees		Number of Full-Time Employees
Wisconsin Electric	3,653		3,551
WPS	1,329		1,267
Wisconsin Gas	426		415
PGL	1,339		1,337
NSG	167		166
MERC	216		213
MGU	159		156
WBS	1,043	*	998
ITF	108		105
Other	3		3
Total employees	8,443		8,211


*	Effective January 1, 2016, approximately 500 employees were transferred from Wisconsin Electric and Wisconsin Gas into WBS.



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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
Wisconsin Electric
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 Wisconsin Electric	2,396

WPS
Local 420 of International Union of Operating Engineers, AFL-CIO	917	October 15, 2016

Wisconsin Gas
Local 2150 of International Brotherhood of Electrical Workers, AFL-CIO	91	August 15, 2017
Local 2006 Unit 1 of United Steel Workers of America, AFL-CIO	191	April 30, 2017
Local 2006 Unit 3 of United Steel Workers of America, AFL-CIO	3	February 29, 2016
Total Wisconsin Gas	285

PGL
Local 18007 of Utility Workers Union of America, AFL-CIO	955	April 30, 2018

NSG
Local 2285 of International Brotherhood of Electrical Workers, AFL CIO	121	June 30, 2019

MERC
Local 31 of International Brotherhood of Electrical Workers, AFL CIO	39	May 31, 2016

MGU
Local 12295 of United Steelworkers of America, AFL-CIO CLC	77	January 15, 2017
Local 417 of Utility Workers Union of America, AFL-CIO *	31	February 15, 2016
Total MGU	108

Total represented employees	4,821


*	MGU entered into a labor agreement with Local 417 of Utility Workers Union of America AFL-CIO, which became effective February 16, 2016. The agreement expires on February 15, 2019.



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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 various utility commissions in the states where we serve customers. 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, including adjustments determined under riders, 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 businesses are 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,



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the CSAPR, and other air quality regulations. In addition, the EPA has finalized regulations under the Clean Water Act that govern cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA 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.

Our electric and natural gas utilities 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



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compliance costs than a state compliance plan. We are continuing to analyze the final rule and to work with other stakeholders to 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.

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

Our electric utilities 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 our electric utilities to higher operating costs. If our electric utilities were ever found to be in noncompliance with the mandatory reliability standards, they could be subject to sanctions, including substantial monetary penalties.

Provisions of the Wisconsin Utility Holding Company Act limit our ability to invest in non-utility businesses and could deter takeover attempts by a potential purchaser of our common stock that would be willing to pay a premium for our common stock.

Under the Wisconsin Utility Holding Company Act, we remain subject to certain restrictions that have the potential of limiting our diversification into non-utility businesses. Under the Act, the sum of certain assets of all non-utility affiliates in a holding company system generally may not exceed 25% of the assets of all public utility affiliates in the system, subject to certain exceptions.

In addition, the Act precludes the acquisition of 10% or more of the voting shares of a holding company of a Wisconsin public utility unless the PSCW has first determined that the acquisition is in the best interests of utility customers, investors, and the public. This provision and other requirements of the Act may delay or reduce the likelihood of a sale or change of control of WEC Energy Group. As a result, stockholders may be deprived of opportunities to sell some or all of their shares of our common stock at prices that represent a premium over market prices.

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



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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.

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. Our electric and natural gas utilities 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. In addition, WBS has various capital projects that are primarily related to the development of software applications used to support our utilities.

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



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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.

In 2015, the ICC and the Attorney General of Illinois initiated investigations into our AMRP capital project. Since the investigations are ongoing, it is too early to determine, what effect, if any, the investigations will have on the AMRP.

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 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, stockholders, 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, stockholders 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.



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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.

We are a holding company and rely on the earnings of our subsidiaries to meet our financial obligations.

As a holding company with no operations of our own, our ability to meet our financial obligations and pay dividends on our common stock is dependent upon the ability of our subsidiaries to pay amounts to us, whether through dividends or other payments. Our subsidiaries are separate legal entities that have no obligation to pay any of our obligations or to make any funds available for that purpose or for the payment of dividends on our common stock. The ability of our subsidiaries to pay amounts to us depends on their earnings, cash flows, capital requirements, and general financial condition, as well as regulatory limitations. Prior to distributing cash to us, our subsidiaries have financial obligations that must be satisfied, including, among others, debt service and preferred stock dividends. In addition, each subsidiary's ability to pay amounts to us depends on any statutory, regulatory, and/or contractual restrictions and limitations applicable to such subsidiary, which may include requirements to maintain specified levels of debt or equity ratios, working capital, or other assets. Our utility subsidiaries are regulated by various state utility commissions, which generally possess broad powers to ensure that the needs of the utility customers are being met.

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.



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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.

We may not be able to use tax credits, net operating losses, and/or charitable contribution carryforwards.

We have significantly reduced our consolidated federal and state income tax liability in the past through tax credits, net operating losses, and charitable contribution deductions available under the applicable tax codes. We have not fully used the allowed tax credits, net operating losses, and charitable contribution deductions in our previous tax filings. We may not be able to fully use the tax credits, net operating losses, and charitable contribution deductions available as carryforwards if our future federal and state taxable income and related income tax liability is insufficient to permit their use. In addition, any future disallowance of some or all of those tax credits, net operating losses, or charitable contribution carryforwards as a result of legislation or an adverse determination by one of the applicable taxing jurisdictions could materially affect our tax obligations and financial results.

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 committed bank credit agreements as back-up liquidity, which allows us to access the low cost commercial paper markets.

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


•	A rating downgrade;


•	An economic downturn or uncertainty;


•	Prevailing market conditions;


•	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, and could limit our ability to sustain our current common stock dividend level.



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

There are a number of factors that impact our and our subsidiaries' credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We or any of our subsidiaries could experience a downgrade in ratings if the rating agencies determine that the level of business or financial risk of us, our utilities, 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 certain existing credit facilities;


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


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


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


•	Trigger collateral requirements in various contracts.

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

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

Our electric utilities burn natural gas in several of their 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.

Our Wisconsin electric utilities 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 their respective rate structures. Our natural gas utilities 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 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



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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 the hedging programs of our utilities must be approved by the various state commissions, 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.

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

Illinois utilities' retail customers may choose an alternative natural gas supplier. Transportation customers purchase natural gas directly from third-party natural gas suppliers and use our distribution system to transport the natural gas to their facilities. Because we earn a distribution charge for transporting the natural gas for these customers, these arrangements have little or no impact on our net income.

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 we are unable to successfully manage our benefit plan assets and medical costs, our cash flows, financial condition, or results of operations could be adversely impacted.

Our cost of providing these plans is dependent upon a number of factors, including actual plan experience, changes made to the plans, and assumptions concerning the future. Types of assumptions include earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and our required or voluntary contributions to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. In addition, medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, changes in interest rates, changes in demographics (including the number of retirements), or changes in life expectancy assumptions.



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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 we 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 the two companies 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 our ability to achieve the anticipated benefits of the transaction as and when expected. We 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.

The acquisition may not be accretive to earnings and may cause dilution to our earnings per share, which may negatively affect the market price of our common stock.

We anticipate that the acquisition will be accretive to earnings per share in 2016, which will be the first full year following completion of the transaction. This expectation is based on preliminary estimates that are subject to change. We also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the acquisition, or may be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in our earnings per share or decrease or delay the expected accretive effect of the transaction and contribute to a decrease in the price of our common stock.

We may incur unexpected transaction fees and transaction-related costs in connection with the acquisition.

We incurred a number of expenses associated with completing the acquisition, and expect to incur additional expenses related to combining the operations of the two companies. We may incur additional unanticipated costs in the integration of the businesses. Although we expect that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses of the two companies, will offset the incremental transaction-related costs over time, we may not achieve this net benefit in the near term, or at all.

We recorded goodwill that could become impaired and adversely affect financial results.

The acquisition of Integrys was accounted for as a purchase in accordance with GAAP. Under the purchase method of accounting, the assets and liabilities acquired and assumed were recorded at their estimated fair values at the date of acquisition and added to those of legacy Wisconsin Energy Corporation. The excess of the purchase price over the estimated fair values was recorded as goodwill. As of December 31, 2015, goodwill totaled $3,023.5 million, of which $2,581.6 million is attributable to the acquisition of Integrys. We perform an analysis of our goodwill balances to test for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment. If goodwill is deemed to be impaired, we may be required to incur material non-cash charges that could materially adversely affect our results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.



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ITEM 2. PROPERTIES

We own our principal properties outright, except 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.

A. REGULATED

Electric Facilities

The following table summarizes information on our electric generation facilities, including owned and jointly owned facilities, as of December 31, 2015:



Name	Location	Fuel	Number of Generating Units	Rated Capacity In MW ⁽¹⁾
Coal-fired plants
Columbia	Portage, WI	Coal	2	353	⁽²⁾
Edgewater	Sheboygan, WI	Coal	1	96	⁽²⁾
Milwaukee County	Wauwatosa, WI	Coal	3	7	⁽³⁾
Oak Creek Expansion	Oak Creek, WI	Coal	2	1,057	⁽⁴⁾
Pleasant Prairie	Pleasant Prairie, WI	Coal	2	1,188
Presque Isle	Marquette, MI	Coal	5	344
Pulliam	Green Bay, WI	Coal	2	212
South Oak Creek	Oak Creek, WI	Coal	4	993
Weston Units 3 and 4	Rothschild, WI	Coal	2	705	⁽²⁾
Total coal-fired plants			23	4,955
Natural gas-fired plants
Concord Combustion Turbines	Watertown, WI	Natural Gas/Oil	4	352
De Pere Energy Center	De Pere, WI	Natural Gas/Oil	1	158
Fox Energy Center	Wrightstown, WI	Natural Gas	3	554
Germantown Combustion Turbines	Germantown, WI	Natural Gas/Oil	5	258
Juneau	Adams, WI	Distillate Fuel Oil	1	—	⁽⁵⁾
Paris Combustion Turbines	Union Grove, WI	Natural Gas/Oil	4	352
Port Washington Generating Station	Port Washington, WI	Natural Gas	2	1,082	⁽⁶⁾
Pulliam	Green Bay, WI	Natural Gas/Oil	1	78
Valley Power Plant	Milwaukee, WI	Natural Gas	2	240
West Marinette	Marinette, WI	Natural Gas/Oil	3	153
Weston	Rothschild, WI	Natural Gas/Oil	3	126
Total natural gas-fired plants			29	3,353
Renewables
Hydro Plants (30 in number)	WI and MI	Hydro	84	146	⁽⁷⁾
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	—
Crane Creek	Howard County, IA	Wind	66	21
Glacier Hills	Cambria, WI	Wind	90	28
Lincoln	Kewaunee County, WI	Wind	14	1
Montfort Wind Energy Center	Montfort, WI	Wind	20	2
Total renewables			365	269
Total system			417	8,577


⁽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.



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⁽²⁾	These facilities are jointly owned by WPS and various other utilities. The capacity indicated for each of these units is equal to WPS's portion of total plant capacity based on its percent of ownership.


•	Wisconsin Power and Light Company, an unaffiliated utility, operates the Columbia and Edgewater units. WPS holds a 31.8% ownership interest in these facilities.


•	WPS operates the Weston 4 facility and holds a 70% ownership interest in this facility. Dairyland Power Cooperative holds the remaining 30% interest.


⁽³⁾	Wisconsin Electric expects to complete the sale of MCPP during the first half of 2016.


⁽⁴⁾	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.


⁽⁵⁾	Wisconsin River Power Company (WRPC) owns and operates the Juneau unit. WPS holds a 50% ownership interest in WRPC and is entitled to 50% of the total capacity from the Juneau unit.


⁽⁶⁾	We Power owns 100% of Port Washington Generating Stations 1 and 2.


⁽⁷⁾	WRPC owns and operates the Castle Rock and Petenwell units. WPS holds a 50% ownership interest in WRPC and is entitled to 50% of the total capacity at Castle Rock and Petenwell. WPS's share of capacity for Castle Rock is 8.1 MWs, and WPS's share of capacity for Petenwell is 10.2 MWs.

As of December 31, 2015, we operated approximately 40,200 pole-miles of overhead distribution lines and 31,100 miles of underground distribution cable, as well as approximately 500 distribution substations and 489,400 line transformers.

Natural Gas Facilities

At December 31, 2015, our natural gas properties were located in Illinois, Wisconsin, Minnesota, and Michigan, and consisted of the following:


•	Approximately 44,200 miles of natural gas distribution mains,


•	Approximately 1,100 miles of natural gas transmission mains,


•	Approximately 2.3 million natural gas lateral services,


•	Approximately 500 natural gas distribution and transmission gate stations,


•	A 3.9 billion-cubic-foot underground natural gas storage field located in Michigan,


•	A 38.3 billion-cubic-foot underground natural gas storage field located in central Illinois,


•	A 2.0 billion-cubic-foot liquefied natural gas plant located in central Illinois,


•	A peak-shaving facility that can store the equivalent of approximately 80 MDth in liquefied petroleum gas located in Wisconsin,


•	Peak propane air systems providing approximately 2,960 Dth per day, and


•	Liquefied natural gas storage plants with a total send-out capability of 73,600 Dth per day.

Our natural gas distribution system included distribution mains and transmission mains connected to the pipeline transmission systems of ANR Pipeline Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, Northern Natural Pipeline Company, Great Lakes Transmission Company, Viking Gas Transmission, and Michigan Consolidated Gas Company. Our liquefied natural gas storage plants convert and store, in liquefied form, natural gas received during periods of low consumption.

PGL owns and operates a reservoir in central Illinois (Manlove Field), and a natural gas pipeline system that connects

Manlove Field to Chicago with eight major interstate pipelines. The underground storage reservoir also serves NSG under a

contractual arrangement. PGL uses its natural gas storage and pipeline assets as a natural gas hub in the Chicago area.

We also own office buildings, natural gas regulating and metering stations, and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services, and natural gas distribution mains and services occupy private property, we have in some, but not all instances, obtained consents, permits, or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.



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Steam Facilities

As of December 31, 2015, the combined steam systems supplied by the VAPP and MCPP consisted of approximately 42 miles of both high pressure and low pressure steam piping, nine miles of walkable tunnels, and other pressure regulating equipment.

General

Substantially all of PGL's and NSG's properties are subject to the lien of the respective company's mortgage indenture for the benefit of bondholders.

B. CORPORATE AND OTHER

As of December 31, 2015, the corporate and other segment facilities consisted of energy asset facilities owned by PDL and CNG fueling stations owned by ITF.

The energy asset facilities owned by PDL include a portfolio of residential solar facilities, a portfolio of commercial and industrial solar facilities, a landfill gas transportation facility, and a natural gas co-generation facility. The solar facilities consist of distributed solar projects ranging from small residential roof top systems up to commercial and industrial solar systems of 4.5 MWs in size. The total capacity of these solar projects is 27.6 MWs. The majority of the solar facilities are wholly owned by subsidiaries of PDL while one is jointly owned by PDL and Duke Energy Generation Services. PDL's portion of the jointly owned solar capacity is 0.4 MWs. The landfill gas transportation facility in Brazoria County, Texas, has 33 miles of natural gas pipeline connecting a landfill and chemical plant. The natural gas co-generation station in Combined Locks, Wisconsin, has a summer design capacity of 45.5 MWs.

The CNG fueling stations consist of 32 stations that are wholly owned and operated by ITF. Additionally, ITF operates five stations that are owned by EVO Trillium LLC, which is jointly owned by ITF and Environmental Alternative Fuels, LLC. ITF holds a 15% ownership interest in EVO Trillium LLC. The sale of these facilities is currently pending. See Note 3, Dispositions, for more information.

ITEM 3. LEGAL PROCEEDINGS

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

OTHER MATTERS

Litigation Relating to the Acquisition of Integrys

After the announcement of the acquisition, Integrys and its board of directors, along with WEC Energy Group, were named as defendants in ten separate purported class action lawsuits filed in Brown County, Wisconsin (three of the cases – Rubin v. Integrys, et al., Blachor v. Integrys, et al., and Albera v. Integrys, et al.), Milwaukee County, Wisconsin (two of the cases – Amo v. Integrys, et al. and Inman v. Integrys, et al.), Cook County, Illinois (two of the cases – Taxman v. Integrys, et al. and Curley v. Integrys, et al.), and the federal court for the Northern District of Illinois (three of the cases – Steiner v. Integrys, et al., Tri-State Joint Fund v. Integrys, et al., and Collison v. Integrys, et al.). In the Tri-State Joint Fund case, WEC Energy Group’s CEO was also named as a defendant. The cases were brought on behalf of proposed classes consisting of former shareholders of Integrys. The complaints alleged, among other things, that the Integrys board members breached their fiduciary duties by failing to maximize the value to be received by Integrys’s shareholders, that WEC Energy Group aided and abetted the breaches of fiduciary duty, and that the joint proxy statement/prospectus contained material misstatements and omissions. The Brown County and Cook County cases were dismissed in favor of the Milwaukee County actions. On November 12, 2014, the parties entered into a Memorandum of Understanding which provided the basis for a complete settlement of these actions. A Stipulation of Settlement was presented to the Court in late July 2015. On December 17, 2015, the Court approved the settlement and entered a final judgment in this matter, which resulted in the complete dismissal of all remaining actions. The period to appeal the Court's order terminates on March 16, 2016.

See Note 18, Commitments and Contingencies, and Note 22, Regulatory Environment, for more information on material legal proceedings and matters related to us and our subsidiaries.



2015 Form 10-K	35	WEC Energy Group, Inc.

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ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.



2015 Form 10-K	36	WEC Energy Group, Inc.

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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.


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